AS/NZS 7000:2016
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AS/NZS 7000:2016
Australian/New Zealand Standard™
Overhead line design
AS/NZS 7000:2016
This Joint Australian/New Zealand Standard was prepared by Joint Technical
Committee EL-052, Electrical Energy Network, Construction and Operation. It was
approved on behalf of the Council of Standards Australia on 17 March 2016 and by
the Standards New Zealand Approval Board on 20 April 2016.
This Standard was published on 17 May 2016.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The following are represented on Committee EL-052:
Australian Energy Council
Australian Services Union
CIGRE
Communications, Electrical and Plumbing Union—Electrical Division
Electrical Regulatory Authorities Council
Electricity Engineers Association (New Zealand)
Energy Networks Association
Keeping Standards up-to-date
Standards are living documents which reflect progress in science, technology and
systems. To maintain their currency, all Standards are periodically reviewed, and
new editions are published. Between editions, amendments may be issued.
Standards may also be withdrawn. It is important that readers assure themselves
they are using a current Standard, which should include any amendments which
may have been published since the Standard was purchased.
Detailed information about joint Australian/New Zealand Standards can be found by
visiting the Standards Web Shop at www.saiglobal.com or Standards New Zealand
web site at www.standards.govt.nz and looking up the relevant Standard in the online catalogue.
For more frequent listings or notification of revisions, amendments and
withdrawals, Standards Australia and Standards New Zealand offer a number of
update options. For information about these services, users should contact their
respective national Standards organization.
We also welcome suggestions for improvement in our Standards, and especially
encourage readers to notify us immediately of any apparent inaccuracies or
ambiguities. Please address your comments to the Chief Executive of Standards
Australia or the New Zealand Standards Executive at the address shown on the back
cover.
This Standard was issued in draft form for comment as DR AS/NZS 7000:2015.
AS/NZS 7000:2016
Australian/New Zealand Standard™
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Overhead line design
First published as AS/NZS 7000:2010.
Second edition 2016.
COPYRIGHT
© Standards Australia Limited/Standards New Zealand
All rights are reserved. No part of this work may be reproduced or copied in any form or by
any means, electronic or mechanical, including photocopying, without the written
permission of the publisher, unless otherwise permitted under the Copyright Act 1968
(Australia) or the Copyright Act 1994 (New Zealand).
Jointly published by SAI Global Limited under licence from Standards Australia Limited,
GPO Box 476, Sydney, NSW 2001 and by Standards New Zealand, PO Box 10729,
Wellington 6011.
ISBN 978 1 76035 481 7
AS/NZS 7000:2016
2
PREFACE
This Standard was prepared by the Joint Standards Australia/Standards New Zealand
Committee EL-052, Electrical Energy Networks, Construction and Operation.
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
This Standard is one of a series of two documents—
1
Overhead line design Standard, which is a Standard that sets the detailed design
requirements for overhead lines.
2
HB 331 Overhead line design, is a handbook providing supporting information,
commentary, worked examples and supporting software (where applicable) for the
design of overhead lines.
Statements expressed in mandatory terms in Notes to Tables and Figures are deemed to be
requirements of this Standard.
The terms ‘normative’ and ‘informative’ have been used in this Standard to define the
application of the appendices to which they apply. A ‘normative’ appendix is an integral
part of a Standard, whereas an ‘informative’ appendix is only for information and guidance.
Major changes in the 2016 edition include the following:
(a)
In Table 6.2, Strength Reduction Factor φ for Component Strength, a new category
‘Foundations designed to yield before structure’ with a range from 0.8 to 1.0 has been
added. It aligns with the current embedment depths for distribution poles;
(b)
In Appendix B, Paragraph B4.2, it is recommended that in region B until more
definitive data is available, designers should select one higher level of line security
for convective winds to achieve comparable overhead line reliability in all zones.
(c)
Appendix F, Timber poles, has been made normative;
(d)
A new Appendix FF, structural Test for Prototype Poles, has been added;
(e)
The maximum short-circuit temperatures for conductors in Table BB4, Typical
Conductor Operating Temperatures, have been revised;
(f)
Additional guidelines for ice loading have been added to Appendix DD, Snow and Ice
loads;
(g)
In Appendix EE the hand reach clearances for poles (1200 mm to the left and right
and 1700 mm to the rear) have been clarified.
(h)
A number of editorial changes have been made.
3
AS/NZS 7000:2016
CONTENTS
Page
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
SECTION 1 SCOPE AND GENERAL
1.1 SCOPE AND GENERAL ............................................................................................ 7
1.2 USE OF ALTERNATIVE MATERIALS OR METHODS .......................................... 7
1.3 REFERENCED AND RELATED DOCUMENTS ....................................................... 8
1.4 DEFINITIONS............................................................................................................. 8
1.5 NOTATION ............................................................................................................... 1 4
SECTION 2 DESIGN PHILOSOPHIES
2.1 GENERAL ................................................................................................................. 17
2.2 LIMIT STATE DESIGN ............................................................................................ 17
2.3 DESIGN LIFE OF OVERHEAD LINES ................................................................... 19
2.4 ELECTRICAL OPERATIONAL CHARACTERISTICS OF AN OVERHEAD
LINE .......................................................................................................................... 19
2.5 MECHANICAL OPERATIONAL PERFORMANCE OF OVERHEAD LINES ....... 19
2.6 RELIABILITY........................................................................................................... 19
2.7 COORDINATION OF STRENGTH .......................................................................... 19
2.8 ENVIRONMENTAL CONSIDERATIONS............................................................... 20
SECTION 3 ELECTRICAL REQUIREMENTS
3.1 GENERAL CONSIDERATIONS .............................................................................. 21
3.2 CURRENT CONSIDERATIONS .............................................................................. 21
3.3 INSULATION SYSTEM DESIGN ............................................................................ 21
3.4 LIGHTNING PERFORMANCE OF OVERHEAD LINES........................................ 22
3.5 ELECTRICAL CLEARANCE DISTANCES TO AVOID FLASHOVER ................. 22
3.6 DETERMINATION OF STRUCTURE GEOMETRY ............................................... 25
3.7 SPACING OF CONDUCTORS ................................................................................. 26
3.8 INSULATOR AND CONDUCTOR MOVEMENT AT STRUCTURE ..................... 36
3.9 LIVE LINE MAINTENANCE CLEARANCES ........................................................ 39
3.10 CLEARANCES TO OBJECTS AND GROUND ....................................................... 39
3.11 CLEARANCES TO GROUND AND AREAS REMOTE FROM BUILDING,
RAILWAYS AND NAVIGABLE WATERWAYS ................................................... 39
3.12 POWER LINE EASEMENTS.................................................................................... 44
3.13 CORONA EFFECT ................................................................................................... 44
3.14 ELECTRIC AND MAGNETIC FIELDS ................................................................... 45
3.15 SINGLE WIRE EARTH RETURN (SWER) POWERLINES .................................... 45
SECTION 4 CONDUCTORS AND OVERHEAD EARTHWIRES (GROUND WIRES)
WITH OR WITHOUT TELECOMMUNICATION CIRCUITS
4.1 ELECTRICAL REQUIREMENTS ............................................................................ 47
4.2 MECHANICAL REQUIREMENTS .......................................................................... 49
4.3 ENVIRONMENTAL REQUIREMENTS .................................................................. 53
4.4 CONDUCTOR CONSTRUCTIONS.......................................................................... 54
4.5 CONDUCTOR SELECTION .................................................................................... 54
SECTION 5 INSULATORS
5.1 INSULATION BASICS ............................................................................................. 56
5.2 LINE AND SUBSTATION INSULATION COORDINATION ................................ 56
AS/NZS 7000:2016
5.3
5.4
4
ELECTRICAL AND MECHANICAL DESIGN ....................................................... 57
RELEVANT STANDARDS, TYPES AND CHARACTERISTICS OF
INSULATORS........................................................................................................... 58
SECTION 6 BASIS OF STRUCTURAL DESIGN
6.1 GENERAL ................................................................................................................. 59
6.2 REQUIREMENTS ..................................................................................................... 59
6.3 LIMIT STATES ......................................................................................................... 61
6.4 ACTIONS—PRINCIPAL CLASSIFICATIONS ....................................................... 65
6.5 MATERIAL PROPERTIES ....................................................................................... 66
6.6 MODELLING FOR STRUCTURAL ANALYSIS AND SOIL RESISTANCE ......... 66
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
SECTION 7 ACTION ON LINES
7.1 INTRODUCTION ..................................................................................................... 68
7.2 ACTIONS, GENERAL APPROACH ........................................................................ 68
7.3 LOAD COMPONENTS ............................................................................................. 72
7.4 LOAD COMBINATIONS ......................................................................................... 73
SECTION 8 SUPPORTS
8.1 INITIAL DESIGN CONSIDERATIONS ................................................................... 75
8.2 MATERIALS AND DESIGN .................................................................................... 75
8.3 CORROSION PROTECTION AND FINISHES ........................................................ 77
8.4 MAINTENANCE FACILITIES................................................................................. 77
8.5 LOADING TESTS .................................................................................................... 78
SECTION 9 FOUNDATIONS
9.1 DESIGN PRINCIPLES .............................................................................................. 81
9.2 SOIL INVESTIGATION ........................................................................................... 81
9.3 BACKFILLING OF EXCAVATED MATERIALS ................................................... 82
9.4 CONSTRUCTION AND INSTALLATION .............................................................. 82
SECTION 10 EARTHING SYSTEMS
10.1 GENERAL PURPOSE ............................................................................................... 83
10.2 EARTHING MEASURES AGAINST LIGHTNING EFFECTS ................................ 83
10.3 DIMENSIONING WITH RESPECT TO CORROSION AND MECHANICAL
STRENGTH .............................................................................................................. 83
10.4 DIMENSIONING WITH RESPECT TO THERMAL STRENGTH .......................... 84
10.5 DESIGN FOR EARTH POTENTIAL RISE (EG-0 APPROACH) ............................. 84
10.6 DESIGN FOR EARTH POTENTIAL RISE (EEA APPROACH).............................. 93
10.7 ELECTRICAL ASPECTS OF STAYWIRE DESIGN ............................................. 100
10.8 CHOICE OF EARTHING MATERIALS ................................................................ 101
SECTION 11 LINE EQUIPMENT—OVERHEAD LINE FITTINGS
11.1 GENERAL ............................................................................................................... 1 02
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 TEST REQUIREMENTS......................................................................................... 104
5
AS/NZS 7000:2016
SECTION 12 LIFE EXTENSION (REFURBISHMENT, UPGRADING, UPRATING) OF
EXISTING OVERHEAD LINES
12.1 GENERAL ............................................................................................................... 1 05
12.2 ASSESSMENT OF STRUCTURES ........................................................................ 105
12.3 COMPONENT CAPACITY .................................................................................... 106
12.4 PROOF LOADING.................................................................................................. 106
12.5 UPGRADING OF OVERHEAD LINE STRUCTURES .......................................... 106
SECTION 13 PROVISIONS FOR CLIMBING AND WORKING AT HEIGHTS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
SECTION 14 CO-USE OF OVERHEAD LINE SUPPORTS (SIGNAGE, BANNERS,
COMMUNICATIONS CARRIER CABLES, TELECOMMUNICATIONS REPEATERS)
14.1 SIGNS AND BANNERS AND TRAFFIC MIRRORS ............................................ 108
14.2 COMMUNICATIONS CARRIER CABLES ........................................................... 110
14.3 TELECOMMUNICATIONS REPEATERS EQUIPMENT AND TRAFFIC
MIRRORS ............................................................................................................... 110
14.4 FLAGS ................................................................................................................... . 111
APPENDICES
A
REFERENCE AND RELATED DOCUMENTS ..................................................... 112
B
WIND LOADS ........................................................................................................ 120
C
SPECIAL FORCES ................................................................................................. 132
D
SERVICE LIFE OF OVERHEAD LINES ............................................................... 139
E
DESIGN FOR LIGHTNING PERFORMANCE ...................................................... 149
F
TIMBER POLES ..................................................................................................... 151
G
LATTICE STEEL TOWERS (SELF SUPPORTING AND GUYED MASTS) ........ 158
H
ELECTRICAL DESIGN ASPECTS ........................................................................ 163
I
CONCRETE POLES ............................................................................................... 166
J
COMPOSITE FIBRE POLES .................................................................................. 169
K
STEEL POLES ........................................................................................................ 170
L
STRUCTURE FOOTING DESIGN AND GUIDELINES FOR THE
GEOTECHNICAL PARAMETERS OF SOILS AND ROCKS ............................... 172
M
APPLICATION OF STANDARDIZED WORK METHODS
FOR CLIMBING AND WORKING AT HEIGHTS ................................................ 201
N
UPGRADING OVERHEAD LINE STRUCTURES ................................................ 202
O
WATER ABSORPTION TEST FOR CONCRETE ................................................. 210
P
INSULATION GUIDELINES ................................................................................. 213
Q
CONDUCTOR BLOW OUT AND INSULATOR SWING ..................................... 216
R
CONDUCTOR SAG AND TENSION ..................................................................... 219
S
CONDUCTOR TEMPERATURE MEASUREMENT AND
SAG MEASUREMENT .......................................................................................... 231
T
RISK BASED APPROACH TO EARTHING.......................................................... 238
U
CONDUCTOR PERMANENT ELONGATION (CREEP) ...................................... 257
V
CONDUCTOR MODULUS OF ELASTICITY ....................................................... 259
W
CONDUCTOR COEFFICENT OF THERMAL EXPANSION................................ 262
X
CONDUCTOR DEGRADATION AND SELECTION FOR DIFFERING
ENVIRONMENTS .................................................................................................. 263
Y
CONDUCTOR STRESS AND FATIGUE ............................................................... 267
Z
CONDUCTOR SHORT TIME AND SHORT-CIRCUIT RATING ......................... 275
AA CONDUCTOR ANNEALING AND OPERATING TEMPERATURES ................. 278
BB MECHANICAL DESIGN OF INSULATOR—LIMIT STATES ............................. 284
CC EASEMENT WIDTH .............................................................................................. 285
DD SNOW AND ICE LOADS ....................................................................................... 286
AS/NZS 7000:2016
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
EE
FF
6
DETERMINATION OF STRUCTURE GEOMETRY ............................................. 293
STRUCTURAL TEST FOR PROTOTYPE POLES ................................................ 296
7
AS/NZS 7000:2016
STANDARDS AUSTRALIA/STANDARDS NEW ZEALAND
Australian/New Zealand Standard
Overhead line design
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
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
This Standard specifies the general requirements that are to be met for the design and
construction of new overhead lines to ensure that the line is suitable for its intended
purpose, and provides acceptable levels of safety for construction, maintenance and
operation, and meets requirements for 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’.
Where the additional loading does not exceed the foundation or major structural element
capacities, it is not necessary to comply with this Standard. Modifications may be made to
comply with the Standard applicable to the original design. Major structural elements
include poles, lattice tower legs and foundations.
However, where existing overhead lines are proposed to be altered such that elements of the
overhead line may be overloaded or overstressed to the original design standard; then the
overhead line is required to be 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 aerial line conductor/earth wire
systems or as separate cables supported by the supports. These telecommunication systems
include optical ground wires (OPGWs), optical conductors and all dielectric self supporting
(ADSS) cables.
It is also applicable to overhead line structures supporting telecommunications equipment.
The electrical requirements of this standard apply to alternating current (a.c.) systems with
a nominal frequency of 50 Hz.
This Standard does not apply to catenary systems of electrified railways.
NOTE: Overhead line design handbook HB 331 complements this Standard providing further
information and worked examples.
1.2 USE OF ALTERNATIVE MATERIALS OR METHODS
This Standard shall not be interpreted so to prevent innovation or the use of materials or
methods of design or construction not specifically referred to herein.
Alternative methods, dimensions or materials that provide safety and reliability levels equal
to, or greater, than this Standard can be used and are deemed to comply with this Standard.
COPYRIGHT
AS/NZS 7000:2016
8
Special studies shall be carried out to demonstrate comprehensive engineering design
including a risk management assessment. This study shall include appropriate
documentation to show the source of all data in the context of the specific evaluation. It
should include the following, where relevant:
(a)
Departures from this Standard and rationale.
(b)
Reference to other national or international Standards.
(c)
Comparison with other data.
(d)
Analytical methods used.
1.3 REFERENCED AND RELATED DOCUMENTS
See Appendix A for a list of documents referenced in this Standard and for a list of related
documents.
1.4 DEFINITIONS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
For the purpose of this Standard the definitions below apply.
1.4.1 Accidental action
Action, usually of short duration, which has a low probability of occurrence during the
design working life.
NOTE: An accidental action can be expected in many cases to cause severe consequences unless
special measures are taken.
1.4.2 Action
Set of concentrated or distributed forces acting on a structure (direct action), or deformation
imposed on a structure or constrained within it (indirect action).
NOTE: The term load is also often used to describe direct actions. An action can be permanent,
variable or accidental.
1.4.3 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.
1.4.4 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.
1.4.5 Bonding conductor
Conductor providing equipotential bonding.
1.4.6 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.
COPYRIGHT
9
AS/NZS 7000:2016
1.4.7 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.
1.4.8 Clearance
The shortest distance between two objects that may have a potential difference between
them.
1.4.9 Coefficient of variation
Ratio of the standard deviation to the mean value.
1.4.10 Component
One of the different principal parts of the overhead electrical line system having a specified
purpose.
Typical components are supports, foundations, conductors, insulator strings and hardware.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
1.4.11 Conductor
Any bare conductor which is placed above ground, in the open air and is suspended between
two or more supports.
1.4.12 Conductor temperature
Means the average conductor temperature.
1.4.13 Corona
Luminous discharge due to ionization of the air surrounding an electrode caused by a
voltage gradient exceeding a critical value.
NOTE: Electrodes may be conductors, hardware, accessories or insulators.
1.4.14 Covered conductor
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.
1.4.15 Design working life or design life
Assumed period for which a structure, components and elements are to be used for the
intended purpose with anticipated routine maintenance but without substantial repair being
necessary.
1.4.16 Earth current
Current that flows from the main circuit to earth or earthed parts at the fault location
(earth fault location).
1.4.17 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).
1.4.18 Earth fault
Conductive connection caused by a fault between an aerial 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 aerial phase conductors of the same electrical system at
different locations are designated as double or multiple earth faults.
COPYRIGHT
AS/NZS 7000:2016
10
1.4.19 Earth fault current
Current which flows from the main circuit to earth or earthed parts during a fault.
1.4.20 Earth potential rise (EPR)
Voltage between an earthing system and reference or remote earth.
1.4.21 Earth (Reference/remote)
Part of the earth considered as conductive, the voltage of which is conventionally taken as
zero, being outside the zone of influence of the relevant earthing arrangement.
1.4.22 Earth rod
Earth electrode consisting of a metal rod driven into the ground.
1.4.23 Earth surface potential
Voltage between a point on the earth surface and remote earth.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
1.4.24 Earth wire (Overhead)
A conductor connected to earth at some or all supports, which is suspended usually but not
necessarily above the aerial line conductors to provide a degree of protection against
lightning strikes.
NOTE: An earth wire may also contain non-metallic wires for telecommunication purposes.
1.4.25 Earthing
All means and measures for making a proper conductive connection to earth.
1.4.26 Earthing conductor
Conductor which connects that part of the installation which has to be earthed to an earth
electrode.
1.4.27 Earthing system
Electrical system of conductively connected earth electrodes, earthing conductors, bonding
conductors, or metal parts effective in the same way, for example tower footings,
armourings, metal cable sheaths.
1.4.28 Electric field
The electric field is the space surrounding an electric charge and exerts a force on other
electrically charged objects. It is expressed in units of volts per metre (V/m).
1.4.29 Element
One of the different parts of a component. For example, the elements of a steel lattice tower
are steel angles, plates and bolts.
1.4.30 Equipotential bonding
Conductive connection between conductive parts, to reduce the potential differences
between these parts.
1.4.31 Exclusion limit probability of a variable
Value of a variable taken from its distribution function and corresponding to an assigned
probability of not being exceeded.
1.4.32 Failure
State of a structure, component or element whose purpose is terminated, i.e. in which a
component has failed by excessive deformation, loss of stability, overturning, collapse,
rupture, buckling, etc.
COPYRIGHT
11
AS/NZS 7000:2016
1.4.33 Highest system voltage
Maximum continuous value of phase-to-phase voltage.
1.4.34 Horizontal earth electrode
Electrode which is generally buried at a shallow 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.
1.4.35 Impedance to earth of an earthing system
Impedance between the earthing system and reference or remote earth.
1.4.36 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
1.4.37 Insulated with earthed screen
Includes aerial bundled cable (ABC) complying with either AS/NZS 3599.1 or
AS/NZS 3599.2 as applicable.
1.4.38 Insulated without earthed screen
Includes CCT cable complying with AS/NZS 3675.
1.4.39 Laminar wind
Wind on conductor with a speed between approximately 0.5 m/s and 7 m/s which results in
the excitement of Aeolian vibration frequencies on the conductor.
1.4.40 Limit state (electrical)
State beyond which the electrical design performance is no longer satisfied.
1.4.41 Limit state (structural)
State beyond which the structure, components and elements no longer satisfies the design
performance requirements.
1.4.42 Loading condition
Likely design actions with defined variable actions and permanent actions for a particular
structure analysis.
1.4.43 Magnetic field
Magnetic field generated by current carrying conductor. The magnetic field strength, H, is
expressed in amperes per metre (A/m).
1.4.44 Magnetic flux density
The magnetic flux density, ‘B’, is the magnetic field per unit area and expressed in the units
of milliGauss (mG) or microTesla (μT).
1.4.45 Maintenance
Total set of activities performed during the design working life of the system to maintain its
purpose.
1.4.46 Maximum operating temperature
Limiting temperature for electrical clearances.
COPYRIGHT
AS/NZS 7000:2016
12
1.4.47 Nominal voltage
Voltage by which the overhead electrical line is designated and to which certain operating
characteristics are referred.
1.4.48 Optical conductor (OPCON)
An electrical phase conductor containing optical telecommunication fibres.
1.4.49 Optical ground wire (OPGW)
An earth wire containing optical telecommunication fibres.
1.4.50 Overhead line
Conductors or cables together with associated supports, insulators and apparatus used for
the transmission or distribution of electrical energy.
1.4.51 Overhead service line
An overhead line operating at a voltage less than 1000 V generally located between the
electricity utility’s overhead line and the point of connection to an electrical installation.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
1.4.52 Permanent action
Action that is likely to act continuously and for which variations in magnitude with time are
small compared with the mean value.
1.4.53 Potential grading
Influencing the earth surface potential by means of earth (grading) electrodes.
1.4.54 Power frequency flashover distance
Withstand airgap for highest anticipated short-term power frequency voltage and is
typically 1.7 per unit voltage.
1.4.55 Prospective step voltage
The prospective or open circuit voltage that may appear between any two points on the
surface of the earth spaced one metre apart (measured with two driven electrodes and a high
impedance voltmeter).
1.4.56 Prospective touch voltage
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.
1.4.57 Radio interference voltage (RIV)
Any effect on the reception of a radio signal due to an unwanted disturbance within the
radiofrequency spectrum. Radio interference is primarily of concern for amplitudemodulated 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.
1.4.58 Reliability (electrical)
Probability that an electrical system performs a given electrical 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.
COPYRIGHT
13
AS/NZS 7000:2016
1.4.59 Reliability (structural)
Probability that a structural system performs a given mechanical 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.
1.4.60 Return period
Mean statistical interval in years between successive recurrences 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.
1.4.61 Risk
Chance of or exposure to adverse consequences such as loss, injury or death.
1.4.62 Serviceability limit state (electrical)
State beyond which specified service criteria for an electrical performance is no longer met.
1.4.63 Serviceability limit state (structural)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
State beyond which specified service criteria for a structure or structural element are no
longer met.
1.4.64 Soil resistivity
Volume resistivity of the earth in Ohm metres.
1.4.65 Span length
The centre-line horizontal distance between two adjacent supports.
1.4.66 Support
General term for different structure types that support the conductors of the overhead
electrical line.
1.4.67 Support, intermediate
Support for conductors by pin, post or suspension insulators.
1.4.68 Support, suspension
Support for conductors by suspension insulators.
1.4.69 Support, tension or strain
Support for conductors by tension or strain insulators.
1.4.70 Support, terminal (dead-end)
Tension support capable of carrying the total conductor tensile forces in one direction.
1.4.71 System (electrical)
All items of equipment which are used in combination for the generation, transmission and
distribution of electricity.
1.4.72 System (mechanical and structural)
Set of components connected together to form an overhead electrical line.
1.4.73 System that is non-effectively earthed (electrical)
System (electrical) with isolated neutral or resonant earthing.
1.4.74 System that is solidly earthed (electrical)
System (electrical) in which at least one neutral of a transformer, earthing transformer or
generator is earthed directly or via a low impedance.
COPYRIGHT
AS/NZS 7000:2016
14
1.4.75 System with resonant earthing (electrical)
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.
1.4.76 Television interference voltage (TIV)
Special case of radio interference for disturbances affecting the frequency ranges used for
television broadcasting.
1.4.77 Transferred potential
Potential rise of an earthing system caused by a current to earth transferred by means of a
connected conductor (for example a metallic cable sheath, protective earthed neutral
conductor, pipeline, rail) into areas with low or no potential rise relative to reference earth
resulting in a potential difference occurring between the conductor and its surroundings.
NOTE: The definition also applies where a conductor, which is connected to reference earth,
leads into the area of the potential rise.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
1.4.78 Ultimate limit state (electrical)
State associated with electrical failure, such as electrical flashover.
1.4.79 Ultimate limit state (structural)
State associated with collapse, or with other forms of structural failure.
It corresponds generally to the maximum load-carrying resistance of a structure or a
structural element.
1.4.80 Variable action
A time variable action.
1.4.81 Weight span
For a support, means the length of conductor 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.
1.4.82 Wind span
For a support, means the length of conductor 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.
1.5 NOTATION
The quantity symbols used in this Standard shall have the meanings ascribed to them below.
Symbol
Signification
α
= angle of wind to conductor
φ
=
η
= shielding factor
δ
= solidity factor
γ
= soil unit weight
ϕ
= soil angle of friction
γx
= load factors which take into account variability of loads,
importance of structure, safety implications etc.
strength reduction factor which takes into account variability of
material, workmanship etc.
(kN/m3)
COPYRIGHT
15
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Symbol
AS/NZS 7000:2016
Signification
A
= the projected area of one structure section (panel) under (m2)
consideration in a vertical plane along the face for square towers
A*
= the projected area of the structure section under consideration in a (m2)
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 vertical (m2)
plane along the face
C
= drag coefficient of wire
C
= soil cohesion
Cd
= drag force coefficient for member
COV
= coefficient of variation
CRF
= component reliability factor
D
= conductor diameter
(mm)
DE
= ‘effective diameter’ of foundation
(m)
En
= earthquake load corresponding to an appropriate return period
(kN)
Fb
= load on structure due to unbalanced conductor tensions resulting
from abnormal conditions e.g. a broken conductor
Fc
= load on structure resulting from wind action on the projected wind (kN)
area of the conductor
Fsθ
= wind load on tower sections in the direction of the wind
Ft
= load on the structure due to the intact horizontal component of (kN)
conductor tension in the direction of the line for the appropriate
wind load
Ftw
= horizontal component of the conductor tensions in the direction of (kN)
the line when subject to wind
Ft m
= horizontal component of the conductor tensions in the direction of (kN)
the line when subject to maintenance conditions
Fte
= horizontal component of the conductor tension in the direction of (kN)
the line under no wind
G
= vertical dead loads
Gc
= vertical dead load related to conductors
(kN)
Gs
= vertical dead loads resulting from non conductor loads
(kN)
H
= ground line lateral load
(kN)
Hcalc
= calculated value using recommended method
(kN)
HL
= nominal failure load
(kN)
H max.
= maximum lateral load
(kN)
Kθ
= factor for angle of incidence θ of wind to frames
(kN)
Ki
= factor that is function of soil modulus of elasticity and foundation
geometry
(kPa)
COPYRIGHT
(kN)
AS/NZS 7000:2016
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Symbol
16
Signification
Kq, Kc
= factors that are a function of z/D and φ
Kx
= represents factors accounting for aspect ratio, wind direction and
shielding of the member
L
= conductor length under consideration for determining conductor (m)
loads due to wind action e.g. the wind span for a structure
L
= embedment depth or length for structural design
LR
= line reliability
M
= bending moment at ground line
Md
= wind direction multiplier. See AS/NZS 1170.2
Mrel
= reliability based load multiplier for wind loads
Mt
= topographic multiplier
AS/NZS 1170.2
p
= ultimate soil pressure
Pc
= conductor natural and forced convection cooling
Pj
= conductor joule heating due to the resistance of the conductor
Pr
= conductor radiation cooling
Ps
= conductor solar heat gain
Q
= maintenance loads
qz
= dynamic wind pressure
(kPa)
qz
= vertical overburden pressure at depth z, q z = 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
(kN)
Rn
= the nominal strength of the component
(kN)
RP
= return period
(years)
S
= snow and ice loads
(kN)
Sγ
= snow and ice loads corresponding to an appropriate return period
SRF
= span reduction factor to provide for spatial variation in wind
TSRF
= tension section reduction factor to provide for spatial variation in
wind
U
= nominal phase-to-phase voltage
(V)
VR
= regional wind speed. See AS/NZS 1170.2
(m/s)
Vsit,β
= design site wind velocity. See AS/NZS 1170
(m/s)
Wn
= wind load based on selected wind return period or a specified (kN)
design wind pressure
X
= the applied loads pertinent to each loading condition
(kN)
z
= depth below the ground surface
(m)
zr
= point of rotation at a depth below the surface
(m)
for
(m)
(kNm)
gust
wind
speed.
Refer
to
(kPa)
COPYRIGHT
17
S E C T I O N
2
AS/NZS 7000:2016
D E S I G N
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 provide 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 principles from related design
fields (electrical, structural and mechanical) need to be applied whilst incorporating
regulatory, environment and maintenance requirements.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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)
designed to relevant regulations, Australian Standards, New Zealand Standards and
other relevant international standards;
(b)
security (minimal structural or component failures);
(c)
reliability (appropriate outage rates);
(d)
meeting of environmental requirements (electromagnetic fields (EMF), visual, RIV,
TIV and audible noise);
(e)
whole of life cost;
(f)
practicality to construct;
(g)
ability 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 transfer rating requirements.
2.2 LIMIT STATE DESIGN
2.2.1 General
The design of overhead lines shall be based on limit state principles for serviceability and
strength limit states for the various line components.
Structure 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.
The state of system and the serviceability and ultimate strength limits are illustrated in
Figure 2.1.
S t ate of sys te m
Strength limits
I n t a c t s t a te
D a m a g e d s t ate o r
d e f l e c te d s t a te
D a m a g e li m i t
(s e r vi c e a b ili t y
l i m i t s t a te)
Fa i l u r e l i m i t
(u l ti m ate s tr e n g th
l i m i t)
FIGURE 2.1 LIMIT STATE DESIGN
An explanation of limit state design is given in IEC 60826.
COPYRIGHT
Fa il e d s t ate
AS/NZS 7000:2016
18
2.2.2 Limit states on line components
2.2.2.1 General
The overhead line is considered intact when its structure, insulators, conductors and fittings
are used at stresses below the damage limit.
2.2.2.2 Structure design limit states
The 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.
(b)
Serviceability limit state in which the performance of the structure or component
under commonly occurring loads or conditions will be satisfactory.
Serviceability limit states include support deflections. Exceeding the serviceability design
load may cause damage to some components.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTE: A structure or part thereof or component 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.
2.2.2.3 Conductors (including earthwires) limit states
When the conductor is subjected to increasing loads, conductors may exhibit at some load a
permanent deformation particularly if the failure mode is ductile or may exhibit strand
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.
2.2.2.4 Insulator limit states
There are three states for the mechanical design of insulators, as follows:
(a)
Everyday.
(b)
Serviceable wind.
(c)
Ultimate load condition.
The serviceable wind state is the maximum load that can be applied without causing
damage to the insulator or exceeding the desired deflection limit.
2.2.2.5 Electrical structure clearances limit states
Three serviceability states are defined and shall be considered:
(a)
Condition (a)—Low 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 recommended wind pressure of
100 Pa (minimum of 50 Pa).
(b)
Condition (b)—Moderate wind
Under moderate wind with a recommended pressure of 300 Pa (minimum of 100 Pa)
the clearance shall be sufficient to withstand lightning impulse and switching
over-voltages.
COPYRIGHT
19
(c)
AS/NZS 7000:2016
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The service life of an overhead line is the period over which it will continue to serve its
intended purpose safely, without excessive 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 ELECTRICAL OPERATIONAL CHARACTERISTICS OF AN OVERHEAD
LINE
Each overhead line shall be designed to be capable of transferring a prescribed electrical
power, 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 the serviceability limit states.
2.5 MECHANICAL 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 line’s
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 has components
constituting the line as set out below.
Consideration may be given to the coordination of the relative strength of the components
to establish a desired sequence of component failure to minimize overall damage. This
approach provides a hierarchical control of the sequence of failure of components within an
overhead line system, thereby enabling the designer to coordinate the relative strengths of
components and recognizes 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.
COPYRIGHT
AS/NZS 7000:2016
20
TABLE 2.1
OVERHEAD LINE SYSTEM, COMPONENTS AND ELEMENTS
Structural system
Components
Elements
Steel sections, poles cross-arms etc.
Plates, bolts etc.
Supports
Guys and fittings
Anchor bolts, piles, cleats etc.
Foundations
Concrete footing
Soil
Overhead line
Wires
Conductors
Joints
Hardware, shackles etc.
Insulator elements
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Insulators
Brackets, bolts etc.
Fittings
2.8 ENVIRONMENTAL CONSIDERATIONS
All overhead lines should be designed and constructed with consideration for their
environmental impact.
COPYRIGHT
21
S E C T I O N
3
AS/NZS 7000:2016
E L E C T R I C A L
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, corona and
RIV, TIV and audible noise levels.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTE: See Appendix H.
(b)
Power frequency, switching and lightning overvoltages (see Clause 3.3).
(c)
Determination of
(see Clause 3.2).
(d)
Electrical clearances (see Clause 3.5).
(e)
Selection of insulation (see Clause 3.3).
(f)
Lightning performance (see Clause 3.4).
(g)
Design of earthing system (see Section 10).
current
rating
to
meet
power
transmission
requirements
NOTE: Appendix T provides guidance on a risk based approach to earthing.
(h)
Electric and magnetic fields (see Clause 3.14).
The electrical clearances in this Standard apply to a.c. systems with a nominal frequency up
to 60 Hz.
3.2 CURRENT CONSIDERATIONS
The cross-section of the aerial phase conductors shall be chosen so that the design
maximum temperature for the conductor material, determined by grease drop point or
annealing considerations, 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 (See Section 10) shall be designed to withstand
the mechanical and thermal effects due to the fault currents and associated fault durations
and remain serviceable.
3.3 INSULATION SYSTEM DESIGN
3.3.1 General
Overhead equipment will be subjected to the effects of pollution and 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.
NOTE: Reference should be made to Appendix P for guidelines on the design of insulation.
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 consists of the selection of a set of standard
withstand voltages which characterize the insulation.
COPYRIGHT
AS/NZS 7000:2016
22
3.4 LIGHTNING PERFORMANCE OF OVERHEAD LINES
In the northern parts of Australia and those parts of New Zealand where there are moderate
to high ceraunic levels, lightning is a major cause of line outages. The design of the
overhead line should incorporate a reliability target for the lightning performance. A
procedure for the design for lightning performance is covered in Appendix E.
3.5 ELECTRICAL CLEARANCE DISTANCES TO AVOID FLASHOVER
3.5.1 Introduction
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 (watercraft). The
basic approach to electrical clearances is to combine an electrical air gap withstand
distance, (G w) with a safety margin (Sm). Gw is dependent on the electrical breakdown
voltage of air (around 300 kV/m for air gaps up to 2 m), relative air density (RAD) and the
air gap geometry. Sm is dependent on the type of object, the movement of the object and the
exposure of persons in 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.
The clearances to be considered are as follows:
(a)
Clearance at the structure.
(b)
Clearance for inspection and maintenance.
(c)
Mid span phase conductor to phase conductor.
(d)
Conductor to ground.
(e)
Phase conductor to objects.
(f)
Circuit to circuit (attached to same structure or unattached).
In New Zealand, NZECP 34 Code of Practice for Electrical Safe Distance stipulates
electrical clearances for both maintenance and design.
3.5.2 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 the following:
(a)
Deadline inspection and/or maintenance—with 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.
(c)
Live line maintenance—this could include stick or bare hand work either 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.
COPYRIGHT
23
AS/NZS 7000:2016
3.5.3 Live access clearance
During structure access, there is a higher risk of lapse of control than when in the working
position. Climbing corridors on structures which are designed to be accessed live shall be
dimensioned to as follows:
(a)
To accommodate the natural climbing action without requiring the constrained
movement by the climber to maintain safe electrical distances (see climbing space test
in Figure 3.1).
(b)
To maintain at least power frequency flashover distance in the event of a momentary
lapse of controlled movement by the climber.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTE: See hand reach test in Figure 3.1 and application in Appendix EE.
COPYRIGHT
AS/NZS 7000:2016
24
M a i n te n a n c e a p p r o a c h d i s t a n c e
Powe r f r e q u e n cy
f l a s h ove r di s t a n c e
10 0 0
climbing
corridor
170 0
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Hand-reach
clearance
S I D E EL E VAT I O N
C L I M B I N G S PACE T EST
S I D E EL E VAT I O N
H A N D - R E ACH T EST
M a i n te n a n c e a p p r o a c h
distance
Powe r f r e q u e n cy
f l a s h ove r di s t a n c e
120 0
Hand-reach
clearance
e nve l o p e
70 0 l i ve l i n e
wo r k i n g c o r r i d o r
Climbing centre line
50 0 50 0
Climbing
corridor
R E A R EL E VAT I O N
CLIMBING
FIGURE 3.1 ACCESS CLEARANCE TEST
3.5.4 States for calculation of clearances
3.5.4.1 Maximum operating temperature
Vertical clearances shall be based on the maximum operating temperature of the
conductors.
3.5.4.2 Ice load for determination of electrical clearance
The ice load to be applied shall be specified directly based on regional experience.
COPYRIGHT
25
AS/NZS 7000:2016
3.5.4.3 Combined wind and snow/ice loads
Combined wind and snow/ice loads should be considered in certain regions of Australia and
New Zealand, based on regional experience.
NOTE: Appendix DD provides guidance on snow and ice loading.
3.5.4.4 Operating temperature under serviceable wind
The conductor operating temperature under serviceable wind shall be based on the average
ambient temperature for the year.
3.5.5 Clearances at the structure
The three serviceability clearance states which shall be considered are as follows:
(a)
Low wind or still air.
(b)
Moderate wind.
(c)
High wind.
3.6 DETERMINATION OF STRUCTURE GEOMETRY
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
3.6.1 General
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.
NOTE: Appendix EE provides guidance on the determination of structure geometry and
clearances to structure are given in Clause 3.8.2 and Appendix R.
3.6.2 High wind serviceability state
Power frequency clearance shall be provided for high wind serviceability wind pressure.
Insulator swing shall be taken into account when determining the structure geometry.
3.6.3 Moderate wind serviceability state
Switching impulse clearances shall be provided for moderate wind pressure. Insulator swing
shall be taken into account when determining the structure geometry.
Lightning impulse clearances should be considered under moderate wind conditions to
achieve the desired reliability level.
3.6.4 Maintenance clearances
The method of access to the structure shall 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 low winds.
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 see AS 5804.1.
In New Zealand the relevant references are:
(i)
EEA SM-EI.
COPYRIGHT
AS/NZS 7000:2016
(ii)
26
NZECP 34.
(iii) NZECP 46.
3.7 SPACING OF CONDUCTORS
3.7.1 Conductors of different circuits on different supports (unattached crossing)
3.7.1.1 General
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
This Clause provides the minimum requirements to minimize the potential for circuit to
circuit flashover, under both normal operating and fault conditions, between 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 3.2) as follows:
(a)
Where two circuits of different or similar voltage cross each other, conductors of a
higher voltage circuit shall be placed above a lower voltage circuit (except for single
wire earth return (SWER) lines).
(b)
The vertical separation between any conductor or cable of the higher circuit and any
conductor or cable of the lower circuit shall satisfy both of the following conditions:
(i)
Normal conditions clearance—The vertical separation shall be not less than
that specified in Table 3.1.
(ii)
Dynamic loading clearance—See Figure 3.3.
If conditions are such that it is likely that the lower circuit can accidentally contact into the
higher circuit, the vertical separation at the crossing point shall be twice the sag of the
lower circuit at the crossing point when both conductors and cables are at their maximum
operating temperature. (This is a simplified calculation method).
NOTE: Dynamic load can be caused by vegetation falling on conductors or ice shedding.
FIGURE 3.2 UNATTACHED CROSSING
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
27
AS/NZS 7000:2016
FIGURE 3.3 SIMPLIFIED UNATTACHED CROSSINGS FOR DISTURBANCE
CONDITIONS (DOUBLE ENVELOPE METHOD)
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AS/NZS 7000:2016
TABLE 3.1
MINIMUM VERTICAL SEPARATION FOR UNATTACHED CROSSINGS (IN METRES)
UPPER CIRCUIT
U ≤ 500 kV
U > 330 kV
Bare
L
U ≤ 330 kV
U > 275 kV
Bare
U ≤ 275 kV
U >132 kV
Bare
330 kV <U ≤ 500 kV
No wind
5.2
Bare
Wind
3.6
275 kV < U ≤ 330 kV
No wind
5.2
3.8
Bare
Wind
3.6
2.6
132 kV < U ≤ 275 kV
No wind
5.2
3.8
2.8
2.2
U ≤ 132 kV
U > 66 kV
Bare
Bare
Wind
3.6
2.6
66 kV < U ≤ 132 kV
No wind
5.2
3.8
2.8
2.4
E
Bare
Wind
3.6
2.6
2.2
1.5
R
C
33 kV < U ≤ 66 kV
No wind
5.2
3.8
2.8
2.4
1.8
Bare
Wind
3.6
2.6
2.2
1.5
0.8
1000 V < U ≤ 33 kV
No wind
5.2
3.8
2.8
2.4
1.8
U ≤ 33 kV
U > 1000 V
Bare or
covered
U ≤ 33 kV
U > 1000 V
Insulated
Other
U < 1000 V
cables
Bare,
Other cables
(Noncovered and (Conductive)
conductive)
insulated
28
COPYRIGHT
O
W
U ≤ 66 kV
U > 33 kV
Bare
1.2
I
Bare or covered
Wind
3.6
2.6
2.2
1.5
0.8
0.5
R
1000 V < U ≤33 kV
No wind
5.2
3.8
2.8
2.4
1.8
1.2
0.6
C
Insulated
Wind
3.6
2.6
2.2
1.5
0.8
0.5
0.4
U
U ≤ 1000 V
No wind
5.2
3.8
2.8
2.4
1.8
1.2
0.6
0.6
I
Bare, covered and
insulated
Wind
3.6
2.6
2.2
1.5
0.8
0.5
0.4
0.4
T
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
5.2
3.8
2.8
2.4
1.8
1.2
0.6
0.6
0.4
0.4
(Non conductive)
Wind
3.6
2.6
2.2
1.5
0.8
0.5
0.4
0.4
0.2
0.2
NOTES:
1
The above clearances may need to be increased due to local factors.
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 blowout on large spans.
3
The above clearances are based on the upper circuit being at maximum conductor temperature and the lower circuit at ambient temperature.
4
These clearances apply to altitudes up to 1000 m. Correction factors at higher altitudes are contained in AS 2650.
5
The ‘wind’ condition corresponds to serviceable load conditions.
29
AS/NZS 7000:2016
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.
NOTE: Appendix S provides guidance on the measurement of conductor temperature.
The provisions of Clauses 3.7.1.3 and 3.7.1.4 should be used as a guide for selecting
appropriate conductor temperatures and wind pressures.
3.7.1.3 Separation in still air
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The conductor temperature of the higher circuit should be the maximum operating
temperature. The temperature of the lower conductor should be the ambient 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 operating 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 aerial phase
conductors, if applicable.
3.7.1.4 Separation under wind
The conductor temperatures for the upper and lower circuits are given in Table 3.2. The
upper circuit conductors should be assumed to be hanging in the vertical plane with the
wind direction along the span, e.g. conductors not displaced by wind.
The conductor of the lower circuits should be assumed to be displaced by wind pressure
(P), i.e. the wind direction is normal to the span.
NOTE: This assumes that the conductor temperatures of both circuits are at the temperature at
which wind pressure occurs, e.g. conductors have cooled to the air temperature.
Table 3.2 gives the temperature and electrical conditions for determining the electrical
clearances. The ambient temperature is the higher of (a) conductor everyday temperature
or (b) the ambient temperature used to determine the maximum design temperature of the
upper conductor.
TABLE 3.2
CONDITIONS FOR DETERMINING CLEARANCES
Condition, P
Upper conductor
Lower conductor
Clearance
No wind
Max. operating
Ambient
Table 3.1—No wind
Low wind on lower conductor
(100 Pa)
Ambient temp
Ambient temp
Switching impulse or
Table 3.1—Wind
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 provides the minimum requirements to prevent circuit to circuit flashover,
under operating conditions, between conductors or cables that are attached to the same
support and cross each other (see Figure 3.4).
Where two circuits of different or similar voltage cross each other and are attached to the
same support, conductors of a higher voltage circuit shall 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 shall not be less than specified in Table 3.3.
NOTE: For voltages in excess of 132 kV separations should be determined by the designer.
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AS/NZS 7000:2016
30
FIGURE 3.4 ATTACHED CROSSINGS
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
TABLE 3.3
VERTICAL SEPARATION AT SUPPORTS FOR ATTACHED CROSSINGS (IN METRES)
UPPER CIRCUIT
U ≤ 132 kV
U > 66 kV
Bare
66 kV <U ≤ 132 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
33 kV < U ≤ 66 kV
O
Bare (Note 1)
W
1000 V < U ≤ 33 kV
E
Bare or covered
R
1000 V < U ≤ 33 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
2.4
1.8
1.2
0.6
0.3
0.2
0.2
0.2
31
COPYRIGHT
L
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)
NOTES:
The clearances in the table are based on the lower circuit conductors being attached to pin or post insulators. Additional clearance is required to allow 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.
AS/NZS 7000:2016
1
AS/NZS 7000:2016
32
3.7.3 Conductors on the same supports (same or different circuits and shared spans)
3.7.3.1 General
This Clause provides the minimum requirements between 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 conductors or cables are carried on the same pole or support as those of a higher
voltage the lower voltage conductors shall be placed below the higher voltage conductors,
or beside in the case of vertical circuit construction.
Any two bare conductors having a difference in voltage with respect to each other shall
have vertical, horizontal or angular separation from each other in accordance with the
values required by Clause 3.7.3.2 (See Figure 3.5), provided that the clearance at the
support or at any part in the span is not less than the separation nominated in Item (b)
(See Figure 3.6).
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The separation given by Clause 3.7.3.2 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 Clause 3.7.3.3 is a minimum under any circumstances.
3.7.3.2 At mid span
The mid span conductor separation for a single circuit can be determined using
Equation 3.1and Figure 3.5.
FIGURE 3.5 CONDUCTOR SEPARATION AT MID SPAN (ONE CIRCUIT)
X 2 + (1.2Y )2 ≥
U
+ k D + li
150
. . . 3.1
where
X
= is the projected horizontal distance in metres between the conductors at mid
span; (X = (X1 + X2)/2) where X1 is the projected horizontal distance between
the conductors at one support and X2 is the projected horizontal distance
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 = (Y1 + Y2)/2) where Y1 is the projected vertical distance between the
conductors at one support and Y2 is the projected vertical distance between
the conductors at the other support in the same span
COPYRIGHT
33
AS/NZS 7000:2016
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 or between an earthwire and an aerial
phase conductor, regard shall be paid to any phase differences 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. See Note 5 to Figure 3.6.
D
= is the greater of the two conductor sags in metres at the centre of an
equivalent level span and at a conductor temperature with electrical load
(typically 50°C in still air). This may be higher for high temperature
conductors
l
= is the length in metres of any free swing suspension insulator associated with
either conductor. Zero for pin and post insulators
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
For the purposes of this Clause an equivalent level span shall mean a span—
(a)
which has the same span length in the horizontal projection as the original span;
(b)
in which conductor attachments at supports are in the same horizontal plane; and
(c)
in which the horizontal component of the 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 is 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 Cosφ
. . . 3.2
where
Va = upper circuit nominal voltage phase to earth value (kV)
Vb = lower circuit nominal voltage phase to earth value (kV)
φ
= phase angle difference between circuits (degrees)
3.7.3.3 At any point in the span (vertical)
Where U ≤ 11 kV ............................ 0.38 m
Where U > 11 kV ............................ (0.38 + q (U − 11))
. . . 3.3
where
q = constant which varies from 0.005 to 0.01 (normal). Where regional service
experience has shown that other values are appropriate, these may be applied
COPYRIGHT
AS/NZS 7000:2016
34
(a)
(a)
Circuit 1
(b)
(a)
Circuit 2
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
(a) Mid span separation equation 3.1 applies
(b) Equation 3.3 applies at any point between
stacked circuits
FIGURE 3.6 MINIMUM CONDUCTOR SEPARATION—ATTACHED ON SAME
STRUCTURE
NOTES:
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. (See Figure 3.7).
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 provided the covering is adequate to
prevent electrical breakdown of the covering when the conductors clash and a risk
management strategy is in place to ensure that conductors do not remain entangled for periods
beyond what the covering can withstand.
4 Where phase spacers are used, separation 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 Empirical formula 3.1 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)
conductors 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 attachment heights—
k = 0.4 to 0.6.
In all other situations a k factor of 0.4 is recommended.
COPYRIGHT
35
6
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
7
AS/NZS 7000:2016
Mid span clearances may 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.
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. The situations are as follows:
(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
cross-arms.
(c)
Flocks of birds resting on conductors are known to ‘lift off’ simultaneously, causing
excessive 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.
(h)
Fire prone areas (e.g. burning of sugar cane trash) where ionized air will have a
reduced dielectric strength.
FIGURE 3.7 CONDUCTOR SEPARATION—INFLUENCE OF LOAD CURRENT—
ATTACHED ON SAME STRUCTURE
3.7.4 Minimum clearance to inter-span poles
Poles may be installed in between spans to accommodate street lights or low voltage
services and electrical clearance shall be provided for maintenance personnel. The
minimum separation between the circuit at maximum operating temperature and inter-span
pole for voltages up to 33 kV shall be 1.5 m (see Figure 3.8).
COPYRIGHT
AS/NZS 7000:2016
36
Derivation of in span clearance
Upper circuit (up to 33kV )
at max. operating temp
Lowest conductor of the top circuit (up to 33kV)
0.7 m
A p p r oa c h li mi t
to b a r e o r
covered conductor
0. 8 m
Wo r k i n g zo n e
1. 5 m
1. 5 m
Power or
streetlight pole
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
FIGURE 3.8 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 conductors and
any earthed structure to prevent flashover under operating conditions.
This Clause applies to all transmission and distribution lines using bare 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 cross-arms, 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 overvoltages.
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 movements 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 overvoltages resulting from power frequency, lightning
impulse and switching surges constantly changes.
COPYRIGHT
37
AS/NZS 7000:2016
Thus for a freely suspended conductor, both the air gap and the overvoltages 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, ratio of the wind to weight span, and conductor deviation angle.
3.8.2 Structure clearances
Based on the 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The conditions are, Condition (a)—Low wind; Condition (b)—Moderate wind and
Condition (c)—High wind.
Table 3.4 provides recommended structure and conductor clearances for conditions (b) and
(c) for different system and impulse withstand voltages. For condition (a), consideration of
both the live line working distance (as detailed in AS 5804.1 and NZECP46), maintenance
approach distance (NENS04 and NZECP34) and the hand reach clearance (Clause 3.5.3)
needs to be made. Appendix EE provides further guidance.
Clearances should take into account protrusions from the structure (e.g. step bolts) and the
conductor (e.g. corona rings).
See Figure 3.9 for suspension insulator swing angle. 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.
Cross-arm
D i r e c ti o n of wi n d
a n d l i n e d ev i a ti o n
( i f a p p li c a b l e)
E a r th e d s t r u c tu r e
o r c l i m b i n g / wo r k i n g
corridor
A ll owa b l e
swi n g a n g l e
Electrical clearance
to e a r th — Ta b l e 3.4
FIGURE 3.9 CLEARANCE TO STRUCTURES SWING ANGLE
COPYRIGHT
AS/NZS 7000:2016
38
TABLE 3.4
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
MINIMUM CLEARANCES TO EARTHED STRUCTURES (IN METRES)
Nominal system voltage
Un
Lightning/switching
impulse withstand
voltage
kV (r.m.s.)
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
22
150
0.28
0.13
33
200
0.38
0.18
66
350
0.69
0.28
110
550
1.1
0.40
132
650
1.3
0.50
220
950
1.9
0.75
275
1050
2.2
0.90
330
1175
2.6
1.10
400
1250
2.8
1.5
1300
3.1
1.75
1550
4.2
1.75
500
NOTES:
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 birds or animals is experienced or probable.
3
These clearances apply to altitudes up to 1000 m. Correction factors at higher altitudes are
contained in AS 2650.
4
Condition (b) relates to lightning impulse distance and Condition (c) to power frequency
flashover distance.
5
These clearances do not apply to rod gaps.
3.8.3 Calculation of swing angles
The conductor tension 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.
There are other alternative insulator assemblies and appropriate clearances and line actions
which 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 low, moderate and high wind
conditions can be estimated.
NOTE: Appendix Q provides a method of estimating swing angles.
COPYRIGHT
39
AS/NZS 7000:2016
3.9 LIVE LINE MAINTENANCE CLEARANCES
When live line maintenance is required, structures shall be designed to minimum live line
approach clearances as given in AS 5804 and NZECP46.
Reference shall also be made to the provisions set out in Clause 3.6.3.
Other relevant NZ references include EEA Use of Helicopters in Power Company Work.
3.10 CLEARANCES TO OBJECTS AND GROUND
The designer shall have regard for State or National-based Electricity Safety Regulations
which may specify additional or more onerous clearances than stipulated by this Standard.
Where regulations set line design clearances above road pavement these will typically be
based on a minimum electrical clearance (flashover clearance plus margin) plus provision
for the maximum likely vehicle height.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
3.11 CLEARANCES TO GROUND AND AREAS REMOTE FROM BUILDING,
RAILWAYS AND NAVIGABLE WATERWAYS
3.11.1 Clearances to ground and roads
3.11.1.1 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.
The conductors or cables of an overhead line shall 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 operating temperature or move as a result of wind pressure,
shall not be less than the distances specified in Table 3.5.
Departures from these specified distances are permissible where a comprehensive risk
management assessment has been carried out.
In Australia AS 6947 provides guidance on installing power lines across waterways.
In New Zealand, the EEA/Maritime Safety Authority publication Guide to Safety
Management of Power Line Waterway Crossings, provides guidance to protect waterway
users from electrical hazards, as well as protecting power lines and cables from contact by
watercraft and the resultant damage.
COPYRIGHT
AS/NZS 7000:2016
40
TABLE 3.5
MINIMUM CLEARANCE FROM GROUND, LINES OTHER
THAN INSULATED SERVICE LINES
Distance to ground in any direction
m
Nominal system voltage
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
5.5
5.5
4.5
6.0
5.5
4.5
6.7
5.5
4.5
33 V <U ≤ 132 kV
6.7
6.7
5.5
132 kV <U ≤ 275 kV
7.5
7.5
6.0
275 kV <U ≤ ≤ 330 kV
8.0
8.0
6.7
330 kV <U ≤ ≤ 400 kV
9.0
9.0
7.5
≤ 500 kV
9.0
9.0
7.5
U
Bare or insulated conductor or any
other cable U ≤ 1000 V
OR
Insulated conductor with earthed
screen U > 1000 V
Insulated conductor without earthed
screen U > 1000 V
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Bare or covered conductor
1000 V <U ≤ 33 kV
400 kV <U
NOTES:
1
For the purpose of this Clause, the term ‘ground’ includes any unroofed elevated area accessible to plant
or vehicles and the term ‘over’ means ‘across and along’.
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 aged. When conductors are first
erected, an allowance should be made for ‘settling in’ and ‘conductor creep’. See Appendix R.
6
The distances specified 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.
COPYRIGHT
41
AS/NZS 7000:2016
3.11.1.2 Insulated LV service lines
Insulated conductors of an overhead service line shall 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 operating temperature or move as a result of wind
pressure, shall not be less than the distances specified in Table 3.6.
TABLE 3.6
MINIMUM CLEARANCE FROM GROUND,
INSULATED LV SERVICE LINES
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Service line location
Distance to ground in any direction
m
Over the centre of a formed 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
NOTES:
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 snowfields, 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 3.6 are final conditions for conductors
that have aged. When conductors are first erected, an allowance should be
made for ‘settling in’ and ‘conductor creep’. See Appendix R.
5
This Table does not apply where there are local rules and regulations.
3.11.2 Clearances to buildings, other lines and recreational areas
3.11.2.1 Structures and buildings
This Clause specifies the minimum clearance from electrical conductors to any
non-electrical infrastructure such as structures and buildings. The position to which a
conductor in an overhead line may swing under the influence of wind shall be taken into
consideration. See Appendix R for conductor swing angle calculations.
NOTES:
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
(see Figure 3.10). This arc has its centre at the outer extremity of the structure and extends
outward 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 3.7 does not apply to cable systems supported along the facade of a building.
3 Figure 3.10 illustrates the application of Table 3.7 to a particular building. The letters A to D
refer to distances A to D as set out in Table 3.7. The letter G refers to distance to ground.
COPYRIGHT
AS/NZS 7000:2016
42
3.11.2.2 Easements
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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. (See Figure 3.11.)
FIGURE 3.10 STRUCTURE CLEARANCES FOR TABLE 3.7
Co nduc to r
p ositio n under
high wind
S afe t y
clearance
- Ta b l e 3. 8
Insulato r
and
co nduc to r
b l owo u t
D is t a n ce b e t we e n
o u te r co n du c to r s
in s till air
Insulato r
and
co nduc to r
b l owo u t
E as e m e nt co r r i d o r
FIGURE 3.11 EASEMENT CLEARANCES
COPYRIGHT
S afe t y
clearance
- Ta b l e 3. 8
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
TABLE 3.7
CLEARANCES FROM STRUCTURES
U ≤ 1000 V
Clearance
U > 1000 V
1000 V
<U≤
33 kV
33 kV
<U≤
132 kV
132 kV
<U≤
275 kV
275 kV
<U≤
330 kV
330 kV
<U≤
500 kV
Insulated
Bare
neutral
Bare
active
Insulated with
earthed screen
Insulated
without earthed
screen
Bare or
covered
Bare
Bare
Bare
Bare
m
m
m
m
m
m
m
m
m
m
2.7
2.7
3.7
2.7
3.7
4.5
5.0
6.5
7.0
8.0
2.0
2.7
2.7
2.7
2.7
3.7
4.5
6.0
6.5
7.5
1.0
0.9
1.5
1.5
1.5
2.1
3.0
4.5
5.0
6.0
0.1 (2)
0.3 (2)
0.6 (2)
0.1
0.6
1.5
2.5
3.5
4.0
5.0
A
Vertically(1) above those parts of any
structure normally accessible to persons
B
(1)
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
persons but on which a person can stand
D
In any direction from those parts of any
structure not normally accessible to
persons
G
In any direction from ground
43
COPYRIGHT
Vertically above those parts of any
structure not normally accessible to
persons but on which a person can stand
C
See Table 3.5
See Table 3.5
See Table 3.5
(1)
AS/NZS 7000:2016
This 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 3.10. See also Note 1 in Clause 3.11.2.1.
(2)
This clearance can be further reduced to allow for termination at the point of attachment.
NOTES:
1 The interpretation/confirmation of clearances that apply for different situations outlined in this Table may in some instances only be made following reference to
Figure 3.10 to determine an actual clearance that is relevant for a particular application.
2 Clearances in this Table do not apply where there are local rules and regulations. In New Zealand, applicable clearances are given in NZECP34.
AS/NZS 7000:2016
44
3.12 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 living, 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.
NOTE: Appendix CC provides typical easement widths for a range of voltages.
3.13 CORONA EFFECT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
3.13.1 General
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.
3.13.2 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
‘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.
3.13.3 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, government
authority or local council regulations. The total random audible noise consisting of both
broadband and 100 Hz hum needs to be addressed in the design process.
3.13.4 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.
In general if the surface voltage gradient is kept below 16 kV/cm, corona loss will be
negligible compared to joule losses.
COPYRIGHT
45
AS/NZS 7000:2016
3.14 ELECTRIC AND MAGNETIC FIELDS
3.14.1 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 the following:
(a)
For Australia—refer to ARPANSA for the current Standard for Radiation Protection
Standard for Exposure Limits to Electrical and Magnetic Fields 0 Hz–3 kHz.
(b)
For New Zealand—to ICNIRP Guidelines for Limiting Exposure to Time-Varying
Electric, Magnetic, and Electromagnetic Fields (Up to 300 Ghz).
3.14.2 Electric and magnetic field induction
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 relevant Standards and Codes. Relevant Standards and Codes are HB 102
(CJC 6), and AS/NZS 4853.
3.14.3 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) and NZCCPTS Noise Investigation Guide.
3.14.4 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 are given in Appendix H.
3.15 SINGLE WIRE EARTH RETURN (SWER) POWERLINES
3.15.1 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 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, and
in NZECP 41 New Zealand Code of Practice for Single Wire Earth Return Systems.
COPYRIGHT
AS/NZS 7000:2016
46
3.15.2 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.
(c)
The ‘un-isolated’ system that uses a conventional 3-phase backbone from which
single wire tee-off lines emanate.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The design issues to be considered for SWER systems are as follows:
(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
NZECP 41.
(iv)
Interference
with
[see HB88 (CJC 2)].
railway
telecommunications
and
signalling
(v)
Harmonics caused by customer’s equipment overloading SWER system and some
3-phase converting devices.
(vi)
Reduced visibility to low flying aircraft (which may be involved in crop dusting or
fire fighting).
(vii) Low earth fault currents and the difficulty protecting these schemes.
COPYRIGHT
circuits
47
AS/NZS 7000:2016
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 D.C. resistance
The conductor d.c. 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)
published values in relevant Australian and New Zealand Standards on conductors.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
4.1.2 A.C. resistance
The conductor a.c. resistance is a function of the conductor d.c. 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.
NOTE: Appendices AA and BB 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 the
conductor heat balance equation—
Pj + Ps = Pr + Pc
. . . 4.1
where the heat gain terms are Pj which is the joule heating due to the resistance of the
conductor and Ps is the solar heat gain The heat loss terms are Pc which is natural and
forced convective cooling and Pr is the radiant cooling. The heat gain for cyclic magnetic
flux, which is caused by eddy currents, hysteresis and magnetic viscosity; and corona heat
gain are not considered. The evaporative cooling 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 coincident 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
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.
COPYRIGHT
48
CU R R EN T
T EM PER AT U R E
AS/NZS 7000:2016
I2
I1
TIME
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
FIGURE 4.1 SHORT TIME CURRENT RATING AND TEMPERATURE
The final conductor temperature shall not exceed the maximum operating temperature
defined in Clause 1.4.46.
NOTE: See Appendix Z for guidance on establishing the short time thermal current rating for bare
conductors.
Appendix Z provides guidance on establishing the short time thermal current rating for bare
conductors. For covered and insulated conductor the maximum short-term thermal 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 empl.oyed 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 differential expansion of dissimilar materials (known as birdcaging);
(ii)
for covered and or insulated conductors, the insulation temperature rating as specified
in the appropriate Australian and New Zealand Standards;
(iii) the temperature rating of fibre optic cores;
(iv)
the permissible loss of strength due to annealing.
NOTE: See Appendix AA.
COPYRIGHT
49
AS/NZS 7000:2016
(v)
0.5 times, 0.3 times and 0.2 times the melting point of zinc, aluminium and copper
respectively; or
(vi)
the drop point temperature of any grease applied to the conductor.
Appendices AA and BB provide guidance on establishing the short circuit thermal current
rating for bare conductors. For covered and insulated conductors the maximum short circuit
thermal 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.
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 2.1.
Damage and failure limits of conductors and tension fittings are illustrated in a typical
conductor stress strain characteristic illustrated in Figure 4.2.
C o n d u c to r c a l c u l a te d b r e a k i n g l o a d (C B L )
failure limit
= 0. 9 C B L
failure limit
= 0. 9 C B L
te n s i o n f i t t i n g f a i l u r e r e g i o n
s t r e s s s t r a i n c u r ve
a s s u m e d to b e l i n e a r
u p to | 0 . 5 c b l
p e r m a n e nt e l o n g a t i o n
region
e l a st i c e l o n g a t i o n
region
non-linear
model
linear
model
t y p i c a l v i b r a ti o n
damage limit
conductor operating region
using linear model
damage limit
= 0. 5 C B L
conductor operating region
using non-linear model
damage limit
= 0.7 C B L
load (kN)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
| 1.0% s t r a i n
s t r a i n (% e l o n g a t i o n)
FIGURE 4.2 LIMIT STATES OF CONDUCTOR DESIGN
The damage and failure limits of conductors and tension fittings shall be in accordance with
Table 4.1 for the maximum load condition specified in Section 7 and the laminar wind
condition defined in Clause 1.4.39.
COPYRIGHT
AS/NZS 7000:2016
50
TABLE 4.1
DAMAGE AND FAILURE LIMITS OF CONDUCTORS
Conductors and
tension fittings
Damage (serviceability) limit
Failure (strength) limit
Lowest of—
— vibration limit (see Note 1)
Bare
0.9 conductor CBL (see Note 3)
— infringement of clearance
— 0.7 conductor CBL for non-linear model
OR 0.5 conductor CBL for linear
model(see Notes 2 and 3)
ABC and CC
Refer to relevant Australian and New Zealand Standards which are based on
permissible stress methodology
Lowest of—
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
OPGW
— vibration limit (see Note 1); or
— optical fibre failure (rupture)
— 0.7 conductor CBL for non-linear model
OR 0.5 conductor CBL for linear
model(see Notes 2 and 3)
— 0.9 conductor CBL (see Note 3)
— maximum tension corresponding to the
optical fibre strain free condition
Lowest of—
ADSS
— as agreed with the manufacturer
— optical fibre failure (rupture)
— maximum tension corresponding to the
optical fibre strain free condition
— optical tensile stress (rupture)
NOTES:
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 everyday low velocity wind condition defined in Clause 1.4.39.
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 Y provides guidance on conductor tension limits.
2
Failure strength limit state is 0.9 CBL for the tension limits and shall not be exceeded for the
maximum loads specified in Section 7. 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 0.9 factor is based on the failure performance of tensions fittings. Factors greater than 0.9 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 4.2.
COPYRIGHT
51
AS/NZS 7000:2016
TABLE 4.2
CONDUCTOR TENSION DETERMINATION MODELS
Model
Non-linear stress
strain
Application
– conductors with maximum operating temperatures greater than 120°C
– ultimate design tensions exceeding the damage limit of 0.5 conductor CBL
– conductors with maximum operating temperatures less than 120°C
– ultimate design tensions not exceeding the damage limit of 0.5 conductor CBL
Linear stress strain
– steel conductors
– aerial bundled conductors
Conductor permanent elongation shall be taken into account in the determination of
conductor tension change for conductors with catenary constants greater than 1000 m under
everyday conditions.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTES:
1 Appendix U provides guidance on conductor permanent elongation.
2 Appendix R provides guidance on conductor tension 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
performance of overhead lines with conductor damage free endurance based on a service
history with similar conductors, conductor fittings, vibration control, terrain and climates
may be used to validate the conductor vibration limit.
NOTE: Appendix R 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 even if 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 exponential 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.
COPYRIGHT
AS/NZS 7000:2016
52
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.
NOTE: Appendix U provides guidance on conductor permanent elongation.
4.2.5 Conductor annealing and operating temperatures
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 increase 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 short-circuit
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 further allowance is made in Table 4.1 for the
conductor strength reduction factor for annealing.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Annealing shall be considered for copper, aluminium and steel conductors operating at
temperatures greater than 70°, 80° and 200°C respectively.
NOTE: Appendix AA provides guidance on conductor annealing and maximum operating
temperatures.
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; 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)
published values in relevant Australian and New Zealand Standards on insulated
conductors.
Appendix V provides calculations to determine 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)
published values in relevant Australian and New Zealand Standards on insulated
conductors.
NOTE: Appendix W 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.
COPYRIGHT
53
AS/NZS 7000:2016
4.2.9 Conductor diameter
The mean of two measurements at right angles is taken at one cross-section. For
asymmetrical sections, the largest section shall be one of the two measurements.
4.2.10 Conductor drag coefficient
See Appendix B, Paragraph B5.3.
4.2.11 Conductor calculated breaking load
The calculated breaking load (CBL) of a conductor is the characteristic strength of the
conductor and shall be determined from the relevant Australian and New Zealand Standards
for bare conductors and or insulated conductors.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
4.2.12 Conductor vertical and horizontal sag
Conductor vertical sag 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 snow and ice load. Conductor
vertical sag for low-tension spans in particular 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 or ‘blow out’ is a function of the conductor mass, 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
increase in diameter from deposited ice.
Conductor horizontal sag inclusive of 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.
NOTES:
1 Appendix R provides guidance on conductor sag determination.
2 Appendix S provides guidance on conductor sag measurement.
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. 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.
COPYRIGHT
AS/NZS 7000:2016
54
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.
NOTE: Appendix X provides guidance on the selection for various environments.
4.4 CONDUCTOR CONSTRUCTIONS
4.4.1 Bare conductors
Bare conductors shall be supplied and manufactured in accordance with AS 1222.1,
AS 1222.2, AS 1531, AS 1746, AS 3607 or an equivalent International Standard.
4.4.2 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.
4.4.3 Covered conductors
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Covered conductors shall be supplied and manufactured in accordance with the
AS/NZS 3675 or an equivalent International Standard.
4.4.4 Optical fibres
Optical fibre conductors shall be supplied and manufactured in accordance with
international standard description and numbers IEC 60794-4.
4.4.5 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 mm2 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 everyday load should take into account the
working ratings of cable tensioning equipment such as lugalls, comealongs, etc. Also
for three or four core cables, experience has shown that the cores are difficult to
separate to fit insulation piercing connectors at cable tensions exceeding 4.5 kN.
4.4.6 Special conductors
Special conductors such as self-damping, aluminium conductor steel supporting, high
temperature, low wind drag, composite fibre reinforced and shaped conductors may be used
and shall be subject to detailed design considerations by the user.
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
following:
(a)
Electrical requirements for steady state and transient current ratings, corona
discharge, audible noise, RIV, TIV and joule losses.
(b)
Mechanical requirements including 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.
COPYRIGHT
55
(d)
AS/NZS 7000:2016
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).
Other factors to be considered in the conductor selection are wire materials, wire shape,
wire sizes and conductor constructions.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Consideration may also be given to the constructability of conductor systems and the
difficultly of jointing, terminating or suspending such as gapped conductors and twisted
pairs T2, vulnerability to surface damage during erection such as aluminium conductor steel
supported, amount of twisting during runout causing increased static stress in the
penultimate layer, and difficulty erecting bundled phases.
COPYRIGHT
AS/NZS 7000:2016
56
S E C T I O N
5
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 and fittings.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 when the surfaces are lightly wetted because 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.
(d)
Pole top fires where wood poles and cross-arms are used.
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 needs to 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 Ω, 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.
COPYRIGHT
57
AS/NZS 7000:2016
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 loads.
5.3.2 Design for pollution
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 three per unit peak voltage phase to earth can arise
when overhead lines are switched. The extent of this overvoltage is dependent on the
following:
(a)
The point of voltage wave when the line is switched.
(b)
The capacitance or amount of trapped charges on the line.
(c)
Other equipment connected to the line.
When high-speed autoreclosing is installed, overvoltage can exceed 3 per unit voltage,
particularly on transmission 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
Clause 2.2.1.4. The recommendations for the insulator strength reduction factor are given in
Table 6.2.
COPYRIGHT
AS/NZS 7000:2016
58
The serviceable state is at the maximum load that can be applied without causing damage to
the insulator or exceeding the desired deflection limit. The ultimate load condition is
derived from the load combinations given in Table 7.1. The final selection of insulator
mechanical strength can be moderated by the following:
(a)
Load relief due to the slip strength of attachment fittings.
(b)
Design life of the insulator.
(c)
Coordination of strength with other components to provide a hierarchy of control of
the sequence of failure of components.
For line post insulators, the everyday state is a relevant consideration to determine longterm deflection of the insulator.
See Appendix BB for the mechanical design of insulators.
5.4 RELEVANT
INSULATORS
STANDARDS,
TYPES
AND
CHARACTERISTICS
OF
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The Standards that are used to specify the various types of insulators in usage in Australia
are shown in Table 5.1.
TABLE 5.1
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 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
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
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-mechanical 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
COPYRIGHT
59
S E C T I O N
6
B A S I S
O F
AS/NZS 7000:2016
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 reduction factor
appropriate to the reference limit state.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
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.
NOTE: Some States and Territories of Australia and New Zealand may have Acts and
Regulations 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 load conditions 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.
Level II
Applicable to overhead lines where collapse of the line would cause low risk to
life and property and alternative arrangements can be provided if loss of support
services occurs.
Level III
Applicable to overhead lines where collapse of the line would cause elevated
risk to life or significant economic loss to the community and sever vital post
disaster services.
6.2.3 Wind return periods for design working life and security levels
The design loads or wind actions are to be determined based on AS/NZS 1170.2 using the
ultimate limit state wind return periods for the relevant design working life and line security
level given in Table 6.1. Elsewhere in this Standard where wind pressures are specified,
these pressures are to be used to determine the relevant wind actions.
COPYRIGHT
AS/NZS 7000:2016
60
TABLE 6.1
ULTIMATE LIMIT STATE WIND RETURN PERIODS FOR
DESIGN WORKING LIFE AND LINE SECURITY LEVELS
Minimum design return period—all wind regions
Line security level
Design working life
Level I
Level II
5
10
20
<10 years
10
20
40
25 years
25
50
100
50 years
50
100
200
100 years
100
200
400
Temporary construction and
construction equipment, e.g. hurdles
and temporary line diversions with
design life of less than 6 months
Level III
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTES:
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 adopted for a particular structure
or short sections of the line.
3
Temporary structures do not include emergency restoration structures.
4
Designers should be aware that the inverse of the design return period
represents the probability of a wind speed being exceeded in any given year,
not the probability of a wind speed being exceeded over the design working
life of the line.
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 residual loads for broken or terminated
aerial phase conductor are provided to meet this 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 loads,
as defined in Clause 7.2.5 for which line components have to be designed.
6.2.6 Additional considerations
6.2.6.1 Dynamic load effects—Seismic 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.
COPYRIGHT
61
AS/NZS 7000:2016
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.
The effect on 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
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
NOTES:
1 The operating life of an overhead line is 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.
2 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.
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:
φRn > effect of loads ( Wn + ΣγxX)
. . . 6.1
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.
Wn = wind load based on selected return period wind or a specified design wind
pressure
φ
= the strength reduction factor which takes into account variability of material,
workmanship etc.
Rn = the nominal strength of the component
COPYRIGHT
AS/NZS 7000:2016
62
All support structures shall be designed for both ultimate limit states and serviceability
limit states.
6.3.2 Ultimate 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.
Some damage states prior to structural collapse, such as plastic deformation or local
buckling of redundant structural elements may also be treated as ultimate limit states. These
states are, for simplicity, considered in place of the structural collapse itself.
Ultimate strength limit states concern—
(a)
the reliability and security of supports, foundations, conductors and equipment; and
(b)
the safety of people.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 defined conditions beyond which specified
service requirements for an overhead line are no longer met, as follows:
(a)
Mechanical and structural functioning of supports, foundations, conductors and
equipment.
(b)
Maintaining prescribed electrical clearances.
In addition, serviceability limit states that require consideration include the following:
(i)
Deformations and displacements which affect the appearance or effective use of the
support.
(ii)
Vibrations which cause fatigue damage to conductors, supports or equipment or
which limit their functional effectiveness.
(iii) Damage (including cracking) which is likely to affect the durability or the function of
the supports.
(iv)
Conductors, insulators and line accessories adversely affected.
6.3.4 Limit state design
6.3.4.1 General
Limit state design shall be carried out by—
(a)
setting up structural models;
(b)
applying the relevant load cases; and
(c)
verifying that the limit states are not exceeded when design values for loads, 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.
COPYRIGHT
63
AS/NZS 7000:2016
6.3.4.2 Strength reduction factors ( φ)
Table 6.2 gives the range of strength reduction factors applicable to different materials and
elements of an overhead line. It also provides reference to applicable Standards or Sections
of this Standard which will allow further consideration of the appropriate factor for the
material being used. The strength reduction factors ( φ) take into account variability of
material and workmanship for structural components used in overhead lines, as well as
some modification factors. These φ values reflect accepted industry practice.
TABLE 6.2
STRENGTH REDUCTION FACTOR φ FOR COMPONENT STRENGTH
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Part of overhead line (Rn )
Component
Limit state
Strength reduction
factor φ
Reference
Standard
Lattice steel towers
Steel angle
member elements
Strength
See Appendix G
AS 3995
ASCE 10-97
AS 4100
Steel poles and cross-arms
Steel tubular
structure
Strength
See Section 8 and
Appendix K
AS/NZS 4600
AS 4100
ASCE 48-11
EN 50341
AS/NZS 4065
NZS 3101
AS/NZS 4676
NZS 3404
NZS 3404.1
Fasteners
Bolts nuts and
washers
Strength
≤0.9
Unless otherwise
specified
AS/NZS 1559
AS 3995
AS 4100
ASCE 10-97
NZS 3404
NZS 3404.1
Reinforced or prestressed
concrete structures and members
Poles
Cross-arms
Strength
See Section 8 and
Appendix I
Timber pole structures
Strength and
serviceability
See Appendix F
Timber cross-arms (preserved by
full length treatment) (see Note 3)
Strength
AS 1720.1
NZS 3603
Timber cross-arms (preserved by
full length treatment) (see Note 3)
Serviceability
AS 1720.1
NZS 3603
Fibre reinforced composite poles. Poles
Design based primarily on testing
(see Note 7 and Appendix J)
Strength
Cross-arms
Fittings and pins, forged or
fabricated
0.75
(verified from
statistical testing)
Serviceability
0.3
(unverified)
Strength
0.95
(verified from
statistical testing)
AS 3600
AS/NZS 4065
AS/NZS 4676
NZS 3101
EUROCOMP
Design Code and
Handbook
AS 1154
0.8
(unverified)
(continued)
COPYRIGHT
AS/NZS 7000:2016
64
TABLE 6.2 (continued)
Part of overhead line (Rn )
Porcelain or glass cap and pin
string insulator units
Component
Limit state
Strength
Strength reduction
factor φ
0.95
(verified from
statistical testing)
Reference
Standard
AS 3608
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
0.8
(unverified)
(electro-mechanical
strength tested)
Porcelain or glass insulators other
than cap and pin string insulator
units
Strength
0.8
AS 3608
Synthetic composite suspension
or strain insulators (see Note 2)
Serviceability
0.3 to 0.4
Long term
AS 4435.1
Strength
0.7
(short term ultimate
(for one minute
mechanical strength)
Serviceability
0.3 to 0.4
Long term
Strength
0.9
(maximum design
cantilever load)
Other synthetic composite
insulators
Strength
Subject to further
research
Foundations relying on strength
of soil (with conventional soil
testing and/or qualified
inspection)
Strength
0.5 to 0.8
Foundations relying on weight of
soil
Strength
Foundations designed to yield
before structure failure
Strength
0.8 to 1.0
Conductors
Strength
0.9
Serviceability
See Section 4
Stay or guy and termination
(cable) members
Strength
0.7
Stay wire for distribution pole
Strength
0.8
Synthetic composite line post
insulators (see Note 2)
AS 4435.4
See Section 9
See Appendix L
0.8 to 0.9
See Appendix L
COPYRIGHT
AS 1222
AS 3995
ASCE 10–97
65
AS/NZS 7000:2016
NOTES TO TABLE 6.2
1
Design Standards based on limit state formats (usually) take into account exclusion limits and the coefficient
of variation of structural members. The strength reduction factors in the above table include all strength
modification factors (e.g. k factors from Appendix F) applicable to the material.
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
The timber degradation factor k d in Appendix F should be applied to timber cross-arms in addition to the
strength factors used in AS 1720.1 and NZS 3603.
4
Where there are sufficient material property tests of components to provide reasonable statistical data, the φ
factor 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 structures is based on AS 1720.1, the strength reduction factor may be based on the
requirements of that code, however the following should also be taken into account:
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
(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 reduction factor
at the lower end of the range be used in the absence of specific data suggesting high confidence.
7
Composite fibre poles and some steel poles may be highly flexible and deflections may be the limiting design
criteria to ensure electrical clearances are maintained.
8
Foundations designed to yield before structure failure may be considered for distribution overhead pole lines.
6.4 ACTIONS—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 settlement.
Actions are classified by their variation in time—
(i)
Permanent action, i.e. self-weight of supports including foundations, fittings and fixed
equipment
Self-weight of conductors (with associated components) and the effects of the
applicable conductor tension at the reference temperature, as well as uneven
settlements of supports are regarded as permanent actions.
NOTE: The vertical reaction from self-weight of the conductor at the support (in other words
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, 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.
COPYRIGHT
AS/NZS 7000:2016
66
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, i.e. failure containment loads, flood debris loads, avalanches, 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 their nature and/or the structural response as
follows:
(A)
Static actions which do not cause significant acceleration of the components or
elements.
(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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
6.5 MATERIAL PROPERTIES
As a 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 (Rn) values discussed
in Clause 6.3.1.
A multiplier based on the coefficient of variation and number of samples tested shall be
applied in accordance with Clause 8.5.2.3 where testing is used to give the characteristic
strength. These values are used in combination with the strength reduction factor, section
properties and other modification factors to give the design strength of the
component/element ( φRn).
NOTE: Material properties specified in other 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 SOIL RESISTANCE
6.6.1 General
Calculations shall be performed using appropriate design models for the type of structure
being analysed.
For steel lattice towers, member forces caused by the design factored loads shall be
determined by established principles of structural analysis. Variation in member loads
arising from the full range of heights and leg extensions shall be designed for.
Consideration shall also be taken for the effects of foundation settlement.
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. (See 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. Structures tested in a horizontal
configuration may not provide the same assured force distribution as that obtained from
testing in a more realistic vertical configuration.
COPYRIGHT
67
AS/NZS 7000:2016
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/unacceptable
settlement.
settlement
of
the
foundation
(ii)
Imposed deformations on the support or support members.
including
differential
(iii) Inclinations of the support.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
(iv)
Load duration.
Provisions regarding the interaction of loads and recommendations on limit state criteria are
given in Sections 7 and 8.
COPYRIGHT
AS/NZS 7000:2016
68
S E C T I O N
7
A C T I O N
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 Gc.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Gs represents the vertical loads on poles, towers, foundations, cross-arms, 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.
7.2.2 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.
The following wind events and directions shall be considered:
(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 derived at
maximum wind and all relevant vertical loads.
(ii)
Longitudinal direction Apply full longitudinal wind load on the conductors,
insulators, fittings and support, together with corresponding deviation loads and
all relevant vertical loads.
(iii) Oblique (or yawed) wind—(see Appendix B) Apply full oblique wind at an
angle to the transverse axis on the conductors, insulators, fittings and support,
together with deviation loads derived at maximum wind and all relevant vertical
loads.
(b)
Tornado wind (applicable to high security lines—(see Appendix B)
(i)
Apply maximum wind load to the structure only. Wind load to act from any
direction, together with deviation loads at no wind and all relevant vertical
loads.
(ii)
Torsional (for wide transverse structures, e.g. horizontal single circuit towers).
Consideration should be given to the potential for wind causing torsion with
rotation about the support centre.
7.2.3 Snow and ice loads
Snow and ice loadings shall be applied to all elements of an overhead line in appropriate
regions.
NOTE: Appendix DD provides guidance on determining snow and ice loadings.
COPYRIGHT
69
AS/NZS 7000:2016
7.2.4 Special loads
7.2.4.1 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 where very high short-circuits arise, typically
within one span of a substation. These fault currents generally occur for very short
durations.
NOTE: Appendix C provides guidance on forces caused by short-circuit currents.
7.2.4.2 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 that may act on the supports, foundations and/or conductors.
Guidance information on this subject is given in Appendix C.
7.2.4.3 Earthquakes
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
7.2.4.4 Other special loads
Other special loads such as impact from vehicles or flood shall be considered where
appropriate.
7.2.5 Construction and maintenance loads
7.2.5.1 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 design wind pressure for general
maintenance work is recommended at 100 Pa (50 Pa minimum). 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 approximate doubling
of the conductor tension and weight on the structure under consideration.
NOTE: These minimum loadings may be reduced where personnel and equipment is less than the
loads stated in Clause 7.2.5.2, or where work practices reduce or eliminate the loads. This may be
applicable to small lattice towers with short cross-arms.
7.2.5.2 Loads related to line maintenance/construction personnel
The following minimum unfactored loading allowances, for structures with climbing
provisions, shall be made:
(a)
Lattice structures
(i)
Earthwire peaks—provision for two persons plus 100 kg of tools and
equipment.
(ii)
Suspension cross-arms—provision for 2 persons plus 200 kg of tools and
equipment.
(iii) Strain cross-arms—provision for 4 persons plus 500 kg of tools and equipment.
COPYRIGHT
AS/NZS 7000:2016
(b)
70
Pole (subject to personal access)
(i)
Pole head and cross-arm—provision for two persons plus 100 kg of tools and
equipment.
(ii)
Pole—component load of ladder with one person climbing.
The standard allowance for a single person shall be 100 kg.
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 15 kN or 12 kN for limited fall arrest. Under this
condition structural elements needs to be able to restrain this load in an elastic or plastic
deformed state without release of the attached tackle system.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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. 3.0 kN factored point load.
All structural elements that can be climbed and are inclined with an angle less than 30° to
the horizontal shall be designed for the combination of the axial and bending loads under
maintenance load conditions, with a characteristic factored load of 1.5 kN acting vertically
at any point along the member. Where structural members in framing inside the face of the
tower structure are more than 1500 mm from the face of the structure (such as plan bracing
and hip bracing) and can be accessed, they may be designed for a lower characteristic
factored load of 1.0 kN acting vertically at any point.
Climbing steps (of any kind) shall be capable of supporting a concentrated factored load of
1.5 kN acting vertically at a position 50 mm horizontally back from the free end of the
extended step bolt head or step iron end slip restraint.
7.2.6 Coincident temperatures
Temperature effects for the following loading conditions shall be considered in the
determination of conductor tension on overhead lines:
(a)
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)
The ambient temperature assumed for the ultimate wind speed condition.
(c)
A minimum temperature coinciding with a reduced wind speed should be considered,
if relevant. Particular attention is to be given in sub-alpine and alpine regions.
NOTE: Appendix DD provides guidance on determining snow and ice loadings.
(d)
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.
7.2.7 Security loads
7.2.7.1 General
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.
COPYRIGHT
71
AS/NZS 7000:2016
7.2.7.2 Failure containment loads F b
7.2.7.2.1 General
The loads on a structure arising from the failure of an adjacent structure are difficult to
estimate. 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 subjected 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 one or two structures.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 lines 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 pressure. Local experience
may indicate a lower wind pressure is appropriate. This does not preclude ductile failure of
individual structure components (e.g. steel cross-arms or post insulator gain bases) on
intermediate structures, provided that failure of the primary structure component does not
occur and cascade failures of adjacent structures are avoided.
The unbalance tension (Fb) resulting from these broken conductors is the residual static load
(RSL) in the aerial phase conductor after severance of a conductor, or the collapse of a
conductor support system.
Intact conductor tensions (Ft) shall be used for all other conductors.
Fb and Ft 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.
Alternative systems (e.g. stop structures) can be used to limit damage caused by structural
failures.
The failure containment load cases given in Clauses 7.2.7.1.2 and 7.2.7.1.3 do not need to
be applied when assessing existing structures.
7.2.7.2.2 Suspension or intermediate supports
For a single circuit support, the number of conductors to be considered is one phase (with
allowance for bundles) or the earthwire. For two or more circuits, the number of conductors
to be considered is the worst loading combination of two phases in the same span on
opposite sides of the structure, or any phase and earthwire in the same span.
For structure types having limited longitudinal strength alternative failure containment
methods need to be applied (e.g. use of guys).
Alternative systems (e.g. stop structures) can be used to limit damage caused by structural
failures.
The failure containment load cases given in Clauses 7.2.7.1.2 and 7.2.7.1.3 do not need to
be applied when assessing existing structures.
COPYRIGHT
AS/NZS 7000:2016
72
7.2.7.2.3 Tension supports
Single circuit tension supports shall be designed to withstand the longitudinal load of one
earthwire together with one phase. For multiple circuit supports the loads to be considered
shall be the worst combination from the longitudinal load from any two phases on the
multiple or single phase circuit and earthwire in the same span.
7.2.7.2.4 Distribution systems
For poles where foundations or pole top hardware is designed to yield or slip before the
pole ultimate capacity is reached, further failure containment provisions are not necessary
as longitudinal loads will generally be sufficiently reduced by the foundation deformation,
structure and hardware flexibility to limit cascading failures. These flexible designs are
mostly used in, but not limited to, distribution poles.
For tension and terminal distribution pole supports consideration should be given for the
RSL.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
7.2.7.2.5 Residual static load (RSL)
In absence of a more detailed assessment, an RSL factor of 0.70 of intact conductor tension
should be adopted for aerial 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 line, 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.
7.3 LOAD COMPONENTS
7.3.1 Loads from the supported wires
Although any attached conductor (wire) will impose a single force to the structure, this
force is resolved into orthogonal components with respect to the span geometry and then
resolved into orthogonal components with respect to the structure geometry. This allows the
conventional longitudinal, transverse and vertical wire load combination to be calculated
with appropriate load factors for the structure.
NOTE: An overhead line design handbook is proposed to complement this Standard. It is intended
to provide further information and worked examples.
7.3.2 Conductor tensions
7.3.2.1 General
The horizontal component of the conductor tensions Ft used for design shall be based on the
lowest temperature likely to coexist with the design wind pressure as provided in the
following conditions.
7.3.2.2 Wind condition Ft w
Ftw is the horizontal component of the conductor tensions in the direction of the line when
subject to wind
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 strain structures simultaneously.
7.3.2.3 Maintenance condition Ft m
Ft m is the horizontal component of the conductor tensions in the direction of the line when
subject to maintenance conditions.
This condition provides the maximum conductor tension which can be reasonably expected
during construction or maintenance activities. This tension is calculated based on a
recommended transverse wind pressure of 100 Pa (50 Pa minimum). Consideration should
also be given for tension increase under minimum temperature conditions.
COPYRIGHT
73
AS/NZS 7000:2016
7.3.2.4 Everyday condition Fte
Fte 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 (Te) for the line location. This tension is calculated in still air and the everyday
temperature for the region.
7.4 LOAD COMBINATIONS
7.4.1 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 and individual
supports may be subjected to throughout its service life. The load factors in Table 7.1
reflect the uncertainty in the derivation of the particular load. The value of each load
component shall be calculated separately for each loading condition.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
These shall include the potential effects of differential wire tensions across the structure
due to the effects of unequal spans and wind pressures that may exist at the structure.
7.4.2 Deflections and serviceability limit state
Under the serviceability loading condition the deflection shall be limited to a value that
ensures the electrical clearances will not be infringed. This condition may also be used as
an upper limit for cracking criteria in pre-stressed concrete poles.
The serviceability damage limit loading condition shall be used where the damage is of a
ductile nature.
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
LOAD CONDITIONS AND LOAD FACTORS
Loading condition
Wn (based on q z )
Load factor and application
Sγ
Gs
Gc
F tm
F tw
Maximum wind and maximum weight
qz
(see Note 2)
1.1
1.25
1.25
Maximum wind and minimum weight
qz
(see Appendix B)
0.9
0.0
(see Note 1)
1.25
Maximum wind and uplift
qz
(see Appendix B)
0.9
1.25
(see Note 1)
1.25
1.1
1.25
1.1
1.25
1.1
0.25q z
(see Appendix B)
1.1
1.25
1.25
Serviceability—deflection limit
(see Note 5)
1.1
1.1
1.0
Serviceability—damage limit
(see Note 5)
1.1
1.1
1.0
0.1 kPa
1.1
1.5
(see Note 4)
1.0
(see Note 3)
1.3
Everyday condition (sustained loads)
Snow and ice
Failure containment
Seismic
1.0
Fb
Q
1.1
1.25
74
COPYRIGHT
Maintenance
(see Note 6)
F te
1.5
(see Note 4)
2.0
1.25
NOTES:
1
AS/NZS 7000:2016
TABLE 7.1
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
Loads from all wind directions shall be considered.
3
For concrete poles due considerations for vertical load effects, range from 0.8 to 1.3.
4
Conductor tension and weight of conductors at the cross-arm position under maintenance shall be treated as a live load Q with corresponding load factor of 2.0
when co-existent with construction and maintenance loads as provided in Clause 7.2.5.
5
To be determined based on the structure material and location (e.g. less flexibility may be permitted in built up areas due to proximity of buildings).
6
Appendix DD provides guidance on snow and ice loadings.
75
S E C T I O N
8
AS/NZS 7000:2016
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 Australian
Standards, New Zealand Standards, IEC Standards 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 steel tower designs shall be carried out in accordance with AS 3995, AS 4100, and
ASCE 10-97. Further guidance is given in Appendix G.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
8.2.2 Steel poles
Steel poles shall be designed in accordance with AS/NZS 4677, AS/NZS 4600, AS 4100 or
ASCE 48-05 where appropriate. Further guidance is given in Appendix K.
8.2.3 Concrete poles
Concrete poles shall be designed and manufactured in accordance with the requirements of
AS/NZS 4065, NZS 3101 or AS 3600 where appropriate. Further guidance is given in
Appendix I.
8.2.4 Timber poles
Timber poles shall be designed in accordance with Appendix F.
8.2.5 Fibre reinforced polymer poles
Fibre reinforced polymer poles shall be designed in accordance with the Structural Design
of Polymer Composites, EUROCOMP Design Code and Handbook, and the European
Structural Polymeric Composites Group, 1996.
NOTE: Further guidance is given in Appendix J and Recommended Practice for Fiber-Reinforced
Polymer Products for Overhead Utility Line Structures, ASCE Manuals and Reports on
Engineering Practice No. 104, 2003.
8.2.6 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 steel microfilament fibres;
the design and performance characteristics of the pole element shall be supported by load
tests.
8.2.7 Guyed structures
8.2.7.1 General
A guyed support can be any type of structure that is supported by guy wires for stability
and/or strength. 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.
COPYRIGHT
AS/NZS 7000:2016
76
The additional requirements in Clauses 8.2.7.2 and 8.2.7.3 shall also apply.
8.2.7.2 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, a
nominal design value of L/1000 shall be considered.
(b)
The slackening of one or more guys at different loading conditions shall be taken into
consideration.
8.2.7.3 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
For guyed tower structures, galvanized steel wire strands or steel ropes with steel core shall
be used for the guys, and shall be equipped with 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.
Angle or termination structures should be close to vertical after the stringing of the
conductors at the everyday 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.
COPYRIGHT
77
AS/NZS 7000:2016
8.3 CORROSION PROTECTION AND FINISHES
8.3.1 General
Metallic components of supports may be protected against corrosion in order to meet their
design service life, taking into account the planned maintenance regime and environmental
exposure both above and below ground. The following Clauses set minimum requirements
that should be provided (see AS/NZS 2312).
8.3.2 Galvanizing
All steel material and fastenings used in support structures shall be hot-dip galvanized and
tested in accordance with AS/NZS 4680 or equivalent International Standard unless an
alternative anti-corrosion coating system is utilized.
8.3.3 Metal spraying
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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/aluminium coating over the base metal, performed in accordance with ISO 14713 to
provide zinc deposit thickness not less 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 )
If improved durability is required by painting over galvanizing, guidance should be sought
from AS/NZS 2312.
8.3.5 Use of weather-resistant steels
The use of weather resistance steels requires special design considerations and full-scale
experience.
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.
NOTE: 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.
NOTE: 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 the following:
(a)
Provision of safety information for the general public (e.g. warning signs, telephone
number for emergency contact).
(b)
Prevention of unauthorized climbing.
(c)
Provision of aids to authorized personnel to enable them to correctly identify
energized and de-energized conductors (e.g. circuit identification markings).
(d)
Provision for bonding of earthwire and earthing of the support structure.
(e)
Equipotential bonding.
COPYRIGHT
AS/NZS 7000:2016
78
8.5 LOADING TESTS
8.5.1 General
Full scale loading tests on overhead lines supports, when carried out, shall be generally in
accordance with IEC 60652 and the following provisions. It should be understood that such
tests are a sample test for a particular height structure. Taller or shorter structures of the
same structure type may not have identical performance characteristics.
8.5.2 Tower structures
Full scale load testing may be carried out to verify experimentally the structural capacity, or
assumed force distribution and efficiency of structural element connectivity for a given
structural geometry, and for confirming force distribution in redundant bracing elements.
8.5.3 Pole type structures
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Full-scale 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. Taller or shorter poles of the same structure type may not have identical
performance characteristics.
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.
8.5.3.1 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 test 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.
8.5.3.2 Test requirements
Test loads shall be determined to reflect as closely 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. Typical test arrangements are given in Appendix FF.
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.
COPYRIGHT
79
AS/NZS 7000:2016
8.5.3.3 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.
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 similar types and lengths shall be included in the numbers of
poles tested to select the correct COV factor. Deflection characteristics of repetitive sample
pole tests compared to prototype test deflections provides a useful tool for monitoring
quality of pole product manufacture.
TABLE 8.1
VALUES OF MULTIPLIER FOR TEST LOAD FOR ESTIMATED
COEFFICIENT OF VARIATION
No. of similar units
tested
(see Note 1)
Coefficient of variation of structural characteristics (see Note 2)
5%
10%
15%
20%
25%
30%
1
2
3
1.20
1.17
1.15
1.46
1.38
1.33
1.79
1.64
1.56
2.21
1.96
1.83
2.75
2.36
2.16
3.45
2.86
2.56
4
5
10
1.14
1.13
1.10
1.30
1.28
1.21
1.50
1.46
1.34
1.74
1.67
1.49
2.03
1.93
1.66
2.37
2.23
1.85
30
50
100
1.07
1.05
1.00
1.15
1.10
1.00
1.24
1.17
1.00
1.34
1.24
1.00
1.46
1.33
1.00
1.60
1.42
1.00
NOTES:
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
Material
Method of manufacture/
material grading
Minimum COV%
Steel
Concrete
Timber
All welded
Spun or cast
Mechanical stress
graded
Visually graded
5
5
15
25
NOTE: For on-site welded connections, a higher coefficient of variation may be appropriate.
COPYRIGHT
AS/NZS 7000:2016
80
8.5.4 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.
(b)
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 two minutes.
8.5.5 Test reports
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 re-ordered and reported.
COPYRIGHT
81
S E C T I O N
9
AS/NZS 7000:2016
F O U N D A T I O N S
9.1 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
NOTE: Structure foundation design methods together with typical soil parameters are provided in
Appendix L.
As a general principle, a tower 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 component strength factor, φ , values provided in Table 6.2 are based on a component
reliability factor of 1.0, and take into account the normal high coefficient of variation
(COV) of soil generally. Component strength factors up to 0.9 may be considered where
there is a high level of certainty of the material property of the soil and the design
methodology.
The consequences of partial foundation failure for the typical distribution pole or structure
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 un-stayed deviation structures most likely will
reduce conductor tension loadings.
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 (pΔ effect). This can cause
foundation failure.
9.2 SOIL INVESTIGATION
Where carried out, soil investigations shall be to a depth that includes 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.
COPYRIGHT
AS/NZS 7000:2016
82
9.3 BACKFILLING OF EXCAVATED MATERIALS
When backfilling is used, sufficient compaction shall be carried out to ensure 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.
9.4 CONSTRUCTION AND INSTALLATION
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
COPYRIGHT
83
S E C T I O N
1 0
E A R T H I N G
AS/NZS 7000:2016
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The dimensioning of earthing systems shall consider the following requirements:
(i)
Ensure mechanical strength and corrosion resistance.
(ii)
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 acceptable levels contained in AS/NZS 3835 and
HB 101(CJC5).
10.2 EARTHING MEASURES AGAINST LIGHTNING EFFECTS
Where an overhead earthwire exists, the structure 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. Design parameters for high reliability lines
are given in Appendix E.
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 50341-1. If a different material, for example stainless steel, is used,
this material and its dimensions shall meet the requirements of (i) and (ii) in Clause 10.1.
NOTE: It is acceptable to use steel reinforcing bars embedded in concrete foundations and steel
piles as a part of the earthing system.
COPYRIGHT
AS/NZS 7000:2016
84
10.3.2 Earthing and bonding conductors
For mechanical and electrical reasons, the minimum cross-sections shall be:
(a)
Copper
16 mm2.
(b)
Aluminium
35 mm2.
(c)
Steel
50 mm2.
NOTE: Composite conductors can also be used for earthing provided 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
In some cases steady-state zero-sequence currents should be taken into account for the
dimensioning of the relevant earthing system.
For design purposes, the currents used to calculate the conductor size should take into
account the possibility of future growth.
The fault current may be subdivided in the earth system of the network; 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
Clause 10.4.2 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 rise 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 AS 2067 and
IEEE 80. There is discrimination between fault duration lower than 5 s (adiabatic
temperature rise) and greater than 5 s. The final temperature shall be chosen with regard to
the material and the surroundings.
Nevertheless, the minimum cross-sections in Clause 10.3.2 shall be observed.
10.5 DESIGN FOR EARTH POTENTIAL RISE (EG-0 APPROACH)
10.5.1 Introduction
Standard voltage versus time curves for prospective touch voltage, are provided for earthing
design of overhead line assets. Designs may be conservatively matched to one of the
standard curves to determine a touch voltage limit. Note that touch voltage limits can
conservatively be applied to step voltages. If the boundary conditions do not meet the case
under investigation then a more detailed design approach is required such as described in
Appendix T. For more information on risk based earthing, see ENA EG-0 Power System
Earthing Guide, Part 1: Management Principles. In New Zealand, see EEA Guide to Power
System Earthing Practice.
COPYRIGHT
85
AS/NZS 7000:2016
10.5.2 Standard curves
A series of standard (or predetermined) prospective touch voltage/clearing time curves have
been developed to cover key design cases. Monte Carlo analysis has been used to generate
these curves. The curves defined embody a range of probabilistic factors including:
percentiles of population current withstand and body resistance, footwear resistance and
voltage withstand, and likelihood of presence at the time of a fault. For each case study, the
following information has been included: curve details (figure and equation) and
assumptions governing the range of applicability.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The following comments provide information regarding the background behind the selected
curves:
(a)
Conservatism Wherever possible a conservative approach has been followed in order
to widen the range of applicable conditions for a given curve type.
(b)
Touch duration Contact duration of 4 s has been taken as a general case, except
where otherwise mentioned.
(c)
Surface soil resistivity A low soil resistivity value of 50 Ω-m has been used.
(d)
Standard public footwear A typical distribution of footwear resistance
(see ENA EG-0) has been selected in all cases. There are some situations where this
assumption is not valid such as bare feet at swimming pools, and electrical worker
footwear which would be used inside substations.
(e)
Contact configuration The curves relate to prospective touch voltages, however,
they can be applied very conservatively to prospective step voltages.
(f)
Risk targets All curves relate to a ‘negligible risk’ level for individual (1 in 106 per
year probability of fibrillation) and societal risk.
(g)
Contact scenarios The representative contact scenarios selected are as follows:
(i)
Remote A location where the contact frequency is sufficiently low that the
fault/contact coincidence probability is less than the target fatality probability.
In that case there is no touch voltage target required. For these cases the
earthing design is determined by protection and lightning performance
considerations.
(ii)
Urban interface Asset outside normal public thoroughfare with low frequency
of direct contact by an individual.
(iii) Backyard An area with a contactable metallic structure (e.g. fence, gate)
subject to fault induced voltage gradients. This metallic structure is not a HV
asset but becomes live due to earth fault current flow through the soil.
(iv)
(h)
(i)
MEN contact Contact with LV MEN interconnected metalwork
(e.g. household taps) under the influence of either LV MEN voltage rise and/or
soil potential rise.
Power system asset categories The power system assets have been divided into the
following categories:
(i)
Transmission assets Overhead lines and cables and associated infrastructure
(e.g. poles, earth pits) with system voltages of 66 kV and above.
(ii)
Distribution assets Overhead lines and cables with system voltages less than
66 kV, and distribution transformers with LV secondary.
Fault frequencies and durations The fault frequencies and durations used are listed
with each curve.
COPYRIGHT
AS/NZS 7000:2016
(j)
86
Curve shape selected A conservative curve match has been selected based upon
Monte Carlo analysis to generate curves corresponding to the cases under
consideration.
Table 10.1 summarizes the cases provided and the acronyms used to describe each case.
Each case is characterized by a particular combination of fault rate, contact probability and
series resistance.
TABLE 10.1
CASE STUDY DESCRIPTIONS
Case
E-1
Description
Acronym
Contact with transmission asset in urban interface location.
TU
Contact with distribution asset in urban interface location.
DU
Transmission (≥66kV) and Contact with metalwork in a backyard affected by either
distribution assets (<66kV) transmission or distribution asset.
TDMEN
The following series of curves in Figure 10.1 relate to acceptable prospective touch
voltages associated with earth fault events on transmission and distribution assets. The
transmission cases relate to lines and cables with system voltages of 66 kV and above, and
distribution lines and substations, with fault frequency assumptions given in Table 10.2.
10 0 0 0 0
Pr o s p e c t i ve to u c h vo l t a g e ( Vo l t s)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Contact with MEN connected metalwork (around house)
where MEN or soil is affected by either transmission or
distribution assets.
TDB
TU
DU
10 0 0 0
TDB
TDMEN
10 0 0
10 0
10
0.1
1
10
C l e a r i n g t i m e (s e c)
FIGURE 10.1 TRANSMISSION AND DISTRIBUTION ASSET PROSPECTIVE
TOUCH VOLTAGE CRITERIA
Tables 10.2 and 10.3 describe the basis of each prospective touch voltage curve shown
above. Note that individual risk contact frequency and durations are based upon a ‘typical
maximally’ exposed individual (i.e. 90–95% confidence limit).
COPYRIGHT
87
AS/NZS 7000:2016
TABLE 10.2
CURVE GENERATION DATA
Fault
frequency/yr
Curve
Contact scenario
Footwear
Urban-100 contacts/yr for 4 s for clearing
times to 1 sec (≥66 kV)
Transmission urban
TU
0.1
Standard
135 contacts/yr for 4 s clearing times above
1 s (<66 kV)
Distribution urban
DU
0.1
135 contacts/yr for 4 s
Standard
Transmission
Distribution backyard
TDB
0.1
Backyard-416 contacts/yr for 4 s
Standard
TDMEN
0.1
MEN-2000 contacts/yr for 4 s
Standard
N/A
0.1
Less than 60 off (4 s) contacts for 1 s fault
duration, or less than 75 off (4 s) contacts
for 0.2 s fault duration
Transmission
Distribution MEN
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Remote
N/A
The following points provide an outline of the assumptions behind the fault rates used in
Table 10.2:
(i)
For overhead lines the earthwires conduct the EPR to a number of adjacent structures.
(ii)
For underground cables the earthed screen conducts the EPR.
(iii) Transmission assets—2 km long transmission section (e.g. asset interconnected by
10 spans each up to 200 m in length with an overhead earthwire) contributing at a
fault rate of five faults/100 km/year yielding one fault per 10 years.
(iv)
(v)
Distribution assets—A fault rate of one fault per 10 years relates to a range of
distribution assets including:
(A)
1 km of isolated underground cable @ 10 faults/100km/yr.
(B)
2 by 500 m of underground cable feeding a substation @ 10 faults/100 km/yr.
(C)
1 km line section (e.g. 10 by 100 m) with an earthwire @ 10 faults/100 km/yr.
(D)
2 by 100 m spans without an earthwire @ 40 faults/100 km/yr.
(E)
2 by 100 m spans without an earthwire either side of a pole mounted substation
at 40 faults/100 km/yr.
Remote assets—Assets may be considered as ‘remote’ if they do not require a certain
touch voltage to comply with the risk targets (i.e. coincidence probability below risk
target).
Table 10.3 details the voltage/time points used in the generation of the allowable curves.
TABLE 10.3
DATA POINTS USED IN GENERATION OF CURVES
Curve
Prospective
touch voltage
Clearing
time (s)
0.2
Transmission urban <1 s
TU
8000
Transmission urban >1 s
TU
800
1
Distribution urban
DU
800
1
Transmission distribution backyard
TDB
181
1
TDMEN
121
1
Transmission distribution MEN
COPYRIGHT
AS/NZS 7000:2016
88
Tables 10.4 and 10.5 provide the equations and parmeters that may be used to generate the
curves.
TABLE 10.4
CURVE GENERATION EQUATIONS
Prospective touch voltage characteristic equation
TU
(A + B × Ln(t ) + C × (ln)t )) + D × ( Ln(t )) + E × ( Ln(t )) + F × ( Ln(t )) )
(1 + G × Ln(t ) + H × ( Ln(t )) + I × ( Ln(t )) + K × ( Ln(t )) )
(A + B × t + C × t + D × t + E × t + F × t )
(1 + G × t + H × t + I × t + J × t + K × t )
(A + B × t + C × t + D × t + E × t )
(1 + F × t + G × t + H × t + I × t )
(A + B × t + C × t + D × t + E × t )
(1 + F × t + G × t + H × t + I × t + J × t )
2
3
4
2
DU
4
2
3
2
TDB
TDMEN
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
5
4
0.5
1.5
0.5
1.5
2
2
5
4
3
5
2
2
3
3
5
4
4
5
TABLE 10.5
CURVE GENERATION PARAMETERS
TU
DU
TDB
TDMEN
A
799.42725
8220.3651
97.645156
−649.67186
B
−151.06911
−16049.118
−795.84933
16189.957
C
2134.7725
−3233.5941
2480.8153
−20833.832
D
−2465.5817
22189.669
−3353.6563
−7164.2576
E
957.22069
−17347.089
1882.7004
50476.952
F
−54.963953
8373.5787
−8.6985271
−16.765657
G
2.439744
6.8997717
27.772071
255.8065
H
2.1390046
−48.174695
−38.682025
−743.73193
I
−0.37795247
109.8737
20.292411
852.87544
J
−0.062680222
−118.88136
—
−12.438076
K
0.072177248
51.807561
—
—
10.5.3 Societal risk assessment
10.5.3.1 General
The societal risk associated with each of the assets has also to be assessed for each hazard
scenario with the assumptions and conclusions shown in Table 10.6. Note that the exposure
conditions are based upon average exposure frequency and duration estimates for the
susceptible group of people, and the number of exposed people is based upon the number
who could reasonably be expected to be able to make simultaneous contact with affected
metalwork.
COPYRIGHT
89
AS/NZS 7000:2016
TABLE 10.6
SOCIETAL RISK ASSESSMENT ASSUMPTIONS
Curve
Av. contacts/
person/yr
Av. contacts
duration (s)
Maximum number of
people for <10 6 risk
Transmission urban <1 s
TU
75
4
41
Transmission urban >1 s
TU
75
4
41
Distribution urban
DU
75
4
43
Transmission distribution
backyard
TDB
312
4
42
TDMEN
1500
4
42
Transmission distribution MEN
10.5.3.2 Assumptions
Contacts are based on the expected behaviour of an average person. This has been
approximated as 75% of the number of contacts for a worst case single individual.
10.5.3.3 Application notes
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The following should be considered when assessing societal risk:
(a)
The fault rates chosen are above average for higher transmission voltage assets to
simplify the criteria generated. This does not preclude a utility from reassessing its
own asset class and deriving less stringent criteria if necessary.
(b)
Whenever safety criteria are selected it is important that appropriate technical review
be undertaken (e.g. peer and/or manager review and signoff).
(c)
A surface soil resistivity of 50 Ω-m has been used for all contact cases outside a
major substation fence. This is quite a conservative value as in many instances the
higher surface soil resistivity would add series impedance allowing higher perspective
touch voltages. Figure 10.2 provides an example of the transmission/distribution
MEN contact criteria for a range of soil resistivities.
COPYRIGHT
AS/NZS 7000:2016
90
Prospective touch voltage (volts)
10 0 0 0
T D M EN
T D M EN
T D M EN
T D M EN
T D M EN
-
50 ohmm
10 0 o h m m
500 ohmm
10 0 0 o h m m
20 0 0 o h m m
10 0 0
10 0
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
10
0 .1
1
10
Clearing time (secs)
FIGURE 10.2 SURFACE SOIL RESISTIVITY EFFECT ON TDMEN
PROSPECTIVE TOUCH VOLTAGE CONTACT CASE
10.5.4 Standard curve earthing design process
The design process for earthing is shown in Figure 10.3 as a flow chart. This design process
is based on standard curves (or case matching) where the design is conservatively matched
with a published case. The standard cases are represented as design safety criteria
voltage/time curves (which were probabilistically derived).
COPYRIGHT
91
AS/NZS 7000:2016
from Data Gathering
S te p 2: I n i t i a l C o n c e p t D e s i g n
S te p 3: D e t e r m i n e D e s i g n E P R
S te p 4: D e t a i l e d E a r t h i n g L a y o u t
( E s t i m a te h a z a r d l o c a t i o n s &
m a g n i t u d e s)
S te p 5: S t a n d a r d V/ t C r i t e r i a C h o s e n
( f r o m c a s e s t u d i e s)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Does
d e s i g n m a tc h c a s e s t u d y
c i r c u m s t a n c e s?
N
S te p 4: D o
“Direct Probabilistic”
Design
Y
Does Design
c o m p l y w i t h s e l e c te d
V t / t c c r i te r i a?
N
N
S te p 7: M i t i g a t e / R e d e s i g n
Y
Does Design
c o m p l y w i t h s e l e c te d
V t / t c c r i te r i a?
Y
Powe r S y s te m D e s i g n
C o m p l e te
FIGURE 10.3 POWER FREQUENCY DESIGN FOR STANDARD V/T CRITERIA
The following points (see Table 10.7) summarize the intent of each step within the
preceding design procedure flowchart.
COPYRIGHT
AS/NZS 7000:2016
92
TABLE 10.7
RISK BASED DESIGN AND MANAGEMENT PROCESS
Step
1
Process description
Data gathering and project integration
The validity of any design is contingent on the accuracy of the data used. The data is collected
in a staged manner, as required by the designer.
2
Initial design concept
Determine the earthing system that will likely meet the functional requirements. 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 should be bonded and form part of the earthing system. If not bonded,
verification is necessary to ensure that all safety requirements are met.
3
Determine design EPR
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Based on soil characteristics and the likely proportion of total earth fault currents flowing into
the local earthing system, determine the expected earth potential rise (EPR). Include the full
extent of the system under consideration by including the effect of interconnected primary and
secondary supply systems for each applicable fault scenario.
4
Detailed earthing layout.
Select conductor configuration.
Generate an earthing conductor layout to meet earthing system functional requirements.
Shock hazards-location identification and magnitude.
Identify locations where staff or the public may be exposed to shock hazards. Such hazards
include, touch, step, transfer and hand-to-hand contacts. For each location calculate the
expected shock voltages for each applicable fault scenario identified in Step 3.
5
Standard V/t criteria applicable at hazard locations
Based on the specifics of the design concept and the broader context attempt to match the
design to a standard voltage/time (V/t) curve or curves from the case studies. Conservative
assumptions and comparisons are advisable.
6
Undertake direct probabilistic design
For each shock risk location determine fault/presence coincidence and shock circuit
impedances (e.g. footwear and asphalt) and then the fibrillation probability. For each shock
risk location determine if the magnitude of the shock voltage (Step 4) is less than the
applicable safety criteria (Step 5). The voltage will fall in one of the three categories:
High or intolerable—unacceptable risk. Mitigate the risk.
Intermediate or medium—Reduce the risk to as low as reasonably achievable (ALARA). A risk
cost-benefit analysis may be required to assess the cost of the risk treatment against a range of
criteria. For risks classified to be in the Intermediate Region the cost and practicality of any
mitigation measure is assessed against the reduction in risk.
Low or negligible—Risk generally acceptable, however, risk treatment may be applied if the
cost is low and/or a normally expected practice (e.g. operator equipotential mats within
switchyards). If the EPR is sufficiently low it is a simple matter to classify the whole system
as presenting an acceptably low risk.
7
Design improvement
Improve the design and identify and implement appropriate risk treatment measures. Typical
treatment measures might include global and/or local risk reduction techniques.
8
Lightning and transient design
Consider the need to implement any particular design precautions to manage the impact of
lightning and other transients.
(continued)
COPYRIGHT
93
AS/NZS 7000:2016
TABLE 10.7 (continued)
Step
9
Process description
Construction support
Provide installation support as necessary to ensure design requirements fulfilled and
construction staff safety risk effectively managed.
10
Commissioning program and safety compliance review
Review the installation for physical and safety compliance following the construction phase of
the project. Ensure that the earthing system performs adequately to meet the requirements
identified during the design.
11
Documentation
Documentation is to include the physical installation description (e.g. drawings) as well as
electrical assumptions, design decisions, commissioning data, and monitoring and maintenance
requirements.
10.6 DESIGN FOR EARTH POTENTIAL RISE (EEA APPROACH)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
10.6.1 Introduction
During earth faults on HV network assets, there may be some areas or zones on or around
the structures where hazardous step and touch voltages occur. The risk associated with
these hazardous voltages needs to be managed. This may require a change in design to
eliminate or reduce the risk where required or in cases where the risk of harm is already
acceptably low, no further action is required.
The earthing of overhead lines should comply with either the deterministic approach or a
risk based approach.
The deterministic approach requires the earthing design to maintain the respective touch
and step voltages within particular limits.
Alternatively a risk based approach can be adopted. This requires a process to be followed
where the hazards are identified from applying the criteria detailed in AS/NZS 60479.1. An
analysis is undertaken to quantify the level of exposure that an individual or group of
individuals would have to these hazards.
The EEA/NZ Guide to Power System Earthing Practice describes the approaches that
should be adopted. This section reflects the process as detailed in the Guide. The Guide
contains examples of the calculations for both a deterministic approach and a probabilistic
(risk based) approach. The Guide also contains an example of a simplified approach that
can be considered for transmission lines. The simplification allows calculations to be
undertaken without the use of proprietary software. It allows the touch and step voltage
levels to be approximated on and around the transmission asset.
See Appendix T for the risk based approach to earthing. There are a number of
modifications to Appendix T that need to be made when undertaking a risk based approach
to earthing under the EEA approach. These are listed in Clause 10.6.8.
10.6.2 Risk management flowchart
The flow chart for the approach is contained in Appendix T, Figure T1 and requires only
limited modifications for the EEA approach.
Prior to Step 5 where risks are identified, the EGVR, step, touch and transferred voltages
are calculated and compared against limits.
A risk management flowchart based on the steps shown above is provided in Figure 10.4.
COPYRIGHT
AS/NZS 7000:2016
94
S t e p1: C o l l e c t b a s i c d a t a e a r t h f a u l t c u r r e n t ,
fault clearing time, soil resistivity and probability of ear th fault occurring.
C o n s i d e r E PR t r a n s fe r e f fe c t s o n n e a r by t h i r d p a r t y p l a n t .
S t e p 2 : M i n i m u m d e s i g n to m e e t f u n c t i o n a l r e q u i r e m e n t s
S t e p 3 : C a l c u l a te m a x i m u m e a r t h g r i d vo l t a g e r i s e ( EGV R )
S t e p 4 : D e te r m i n e s te p, to u c h & t r a n s fe r r e d vo l t a g e l i m i t s
Ye s
No
Step 6: Determine actual step, touch & transferred voltages
Ye s
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Step 8: Risk Assessment
No
Identify the risk by identifying all hazards and extent of
hazard zones. This is achieved by comparing voltage limits
(derived in 10.6.8.1) with calculated or measured voltages.
Estimate people exposure to the hazards. Carry out
sensitivity analysis where required.
A s s e s s t h e r i s k a s s o c i a te d w i t h a s t r u c t u r e o r
g r o u p o f s t r u c t u r e s w h e r e a p p r o p r i a te .
A s s e s s a c c o r d i n g to r i s k m a t r i x .
R i s k o u tc o m e
High
I n te r m e d i a te
L ow
Carr y out Cost Benefit Analysis
Step 9:
I m p r ove m e n t o f
design. Apply
risk treatment
options
No
Is risk
reduction
impractical and costs
g r o s s l y d i s p r o p o r t i o n a te
to s a fe t y
g a i n e d?
Step 12: Construction support
Ye s
Risk generally acceptable
Step 13: Commissioning
program and safety
compliance review
S t e p 10 : C h e c k o n o t h e r r e q u i r e m e n t s:
• D e te r m i n e i f l ow vo l t a g e e q u i p m e n t i s
ex p o s e d to exc e s s i ve s t r e s s vo l t a g e . I f
this is the case, proceed with mitigation
measures, which can include separation
o f H V a n d LV e a r t h i n g sy s te m s .
• Lightning and transient design
considerations.
S t e p 11: R e q u i r e m e n t s a r e
f u l f i l l e d?
No
S t e p 14 : D o c u m e n t a t i o n
D e t a i l s of :
• design
• r i s k a n a l y s i s (c o n tex t ,
assumptions, methodology
a n d r e s u l t s)
• risk control options applied
Ye s
Design complete
NOTE: Depending on the asset and the circumstances, the steps in the flowchart may be applied in a different order.
FIGURE 10.4 RISK MANAGEMENT PROCESS
10.6.3 Risk assessment
The risk based method is suitable as a general approach and may be applied to any location.
It is especially suitable for locations where hazard events are relatively rare or where
exposure would be typically very short.
COPYRIGHT
95
AS/NZS 7000:2016
The method determines if hazardous step and touch voltages are present on the basis of
internationally acceptable limits of body currents. It is assumed that where these current
limits are exceeded that it will cause a fatality should a fault occur whilst a person is
located in a hazardous area and contact is being made to the two appropriate surfaces.
The hazard to human beings is that a current will flow through the region of the heart which
is sufficient to cause ventricular fibrillation. Permissible current limits may be derived from
either AS/NZS 60479.1 or IEEE 80. AS/NZS 60479.1 curve c2 is the appropriate curve to
be used for this purpose. For earthing system design, current limits need to be translated
into voltage limits for comparison with the calculated step and touch voltages taking into
account the impedance present in the body current path.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
For the purpose of applying the risk based method, step and touch voltage limits should be
derived based on the following criteria:
(a)
The proportion of current flowing through the region of the heart. For touch voltage
limits left hand-to-feet current path when using AS/NZS 60479.1 curve c2. For step
voltage limits a heart current factor of 0.1 for the foot-to-foot current path rather than
the 0.04 in AS/NZS 60479.1.
(b)
The body impedance along the current path. For voltage limits derived using IEEE 80
current limits, a fixed body impedance of 1000 Ω is used. For voltage limits derived
from AS/NZS 60479.1 curve c2, the AS/NZS 60479.1 50% probability factor for
body impedance curves is used.
(c)
The applicable series resistance such as between the body contact points and the soil
or protective equipment such as shoes.
(d)
The fault duration.
Applying a heart current of 0.04 when determining step voltage limits in accordance with
AS/NZS 60479.1 would produce very high tolerable step voltage limits for ventricular
fibrillation. This level of voltage would potentially cause other serious harmful
consequences from internal injuries, burns, respiratory effects and tissue damage. Therefore
a heart current factor of 0.1 is considered more appropriate when calculating prospective
step voltage limits.
The risk assessment requires the frequency of earth faults to be estimated for a particular
structure or group of structures, and also requires estimation of the level of exposure
individuals may have to the hazards associated with these faults.
The average duration of the earth fault is determined by transmission line protection
performance. Where the transmission line protection can be anticipated to operate in most
cases within a typical time, this time period can be applied in the assessment. Where there
is a short time period between earth fault events (i.e. during an autoreclose cycle), this
would be considered a single event, with a duration of the longer of the earth fault events.
As only limited recorded data may be available for specific structures the assessment may
be based on records of typical fault statistics for similar assets. It may also require the type
of land use to be categorized and typical exposure levels to be applied.
The duration of exposure is the total period of time that an individual is in the potentially
hazardous locations that occur during an earth fault, whilst making contact with the
appropriate two surfaces required to make them hazardous.
Where typical fault statistics are being used, the design of the transmission asset and the
maintenance of the equipment should ensure that there is every likelihood that this level of
performance is achieved. For instance bird guards may need to be considered on
transmission assets that would otherwise be susceptible to unusual levels of earth fault
events from roosting birds. Similarly insulators at certain sites may need to follow a
specific condition assessment process to maintain the typical levels of performance.
COPYRIGHT
AS/NZS 7000:2016
96
Towers fitted with overhead earth wires will be exposed to fault currents when towers
either side have an earth fault. This may increase the earth fault frequency, with the fault
contribution from up to three towers either side being included.
10.6.4 Individual risk
The individual risk represents the risk to an individual. The probability that a dangerous
event may occur, and the resulting determination of the individual risk, should be calculated
using an exposure factor (Ef) and an earth fault frequency factor (Ff).
The exposure factor represents the annual exposure of an individual to hazards on or around
the transmission asset—
Ef =
Total duration of exposure per year (in hours)
Number of hours in a year
. . . 10.1
The earth fault frequency factor (Ff) represents the earth fault frequency—
Ff = average number of hazardous EPR events per year
. . . 10.2
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The probability ‘P’ that the specified hazard event occurs when an individual is exposed to
that hazard—
P = Ef × Ff
. . . 10.3
10.6.5 Societal risk
The societal risk represents the risk that becomes significant when multiple, simultaneous
fatalities would occur.
The societal risk is represented by the equivalent number of people N and accounts for the
reduction in society’s tolerance for injury or fatality to large numbers of people. If n people
are present in the hazard area at any given time then the equivalent number of people is—
n for n <4
N =
. . . 10.4
n2 – ≥4
The scaling factor N may be used to calculate an ‘equivalent probability’ Pe which is
equivalent to the individual risk probability after the adjustment N for societal tolerance has
been introduced—
Pe = N × Ef × Ff
. . . 10.5
10.6.6 Acceptance criteria
The calculated probability should be assessed according to the risk management matrix to
determine a qualitative estimate of the risk associated with a hazard.
Where the probability or equivalent probability is greater than 10−4 the risk is classified
‘high’. This is intolerable and needs to be prevented regardless of cost.
Where it is between 10 −4 and 10−6 the risk is classified ‘intermediate’. In this ALARP
(as low as reasonably practicable) region the period of exposure shall be minimized unless
risk reduction is impractical and costs are grossly disproportionate to safety gained.
Where it is less than 10−6 the risk is classified ‘low’. In this ALARP region the period of
exposure shall be minimized unless costs are disproportionate to the reduction in risk.
10.6.7 Cost evaluation of mitigation
The implementation of a risk mitigation option will often not entirely eliminate the
probability of fatality, but merely reduce the probability to a lower value. A cost-benefit
analysis can be applied using the amount by which the probability has been reduced to
determine whether the risk mitigation option is worthwhile. It may also be applied to rank
mitigation solutions.
COPYRIGHT
97
AS/NZS 7000:2016
To carry out such an analysis, it is necessary to use a ‘value of life’ figure—normally
referred to as the value of statistical life (VoSL).
The asset owner’s liability per year (dollars) is—
L=
VoSL
= VoSL × Pe
Pe −1
. . . 10.6
The present value (PV) for the risk can be calculated using the remaining lifespan of the
asset, the liability per year and the expected rate of interest on an alternative investment.
Y
1
L⎡ ⎛ 1 ⎞ ⎤
= ⎢1 − ⎜
PV = L∑
⎟ ⎥
i
D ⎢ ⎝ 1+ D ⎠ ⎥
i =1 (1 + D )
⎣
⎦
Y
. . . 10.7
where
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
PV = present value (dollars)
L
= the asset owner’s liability per year (dollars)
D
= discount rate (fractional rate of interest)
Y
= number of years which the asset will remain potentially hazardous (years)
To evaluate the cost for a range of risk mitigation solutions, the value of PV can be
combined with the residual PV following the implementation of the risk mitigation.
Consequently where the reduction in PV achieved is slight or the risk is initially negligible,
then the costs for mitigation are disproportionate to the safety gains. The implementation of
the mitigation solution would not then be cost effective. Where the mitigation cost
differences are marginal then the mitigation that is most effective in reducing the risk
would typically be selected. The cost of mitigation should include the cost of maintaining
the mitigation equipment.
An example of the calculation is in Appendix T, Step 9—Risk analysis.
10.6.8 Appendix T
10.6.8.1 General
Appendix T describes a risk based approach, which is broadly aligned to the approach
adopted in EEA/NZ.
There are a number of modifications to Appendix T that need to be made when undertaking
a risk based approach according to EEA/NZ.
These consist of the following:
(a)
Voltage limits are calculated based on criteria in AS/NZS 60479.1.
(b)
Voltage limits may also include the use of footwear. A value of 2000 Ω per shoe is
applied.
(c)
The probability of fibrillation is assumed to be 1 for voltages exceeding the
respective voltage limits.
(d)
Societal risk calculation for EEA method is given in EEA/NZ Guide to Power System
Earthing Practice and Appendix T, Example 3. EG-0 societal risk calculation method
is given in Appendix T, Paragraph T7.
10.6.8.2 Deterministic approach for design for earth potential rise
The deterministic approach requires the earthing design to maintain the respective touch
and step voltages within particular limits.
COPYRIGHT
AS/NZS 7000:2016
98
Permissible touch voltage curves have been determined based on AS/NZS 60479.1 for
Special and Normal Locations and for a range of ground conditions. The criteria detailed in
AS/NZS 60479.1 apply.
The limits are such that they are unlikely to be achieved for transmission line assets unless
an overhead or underslung earthwire is installed.
Loaded voltages can be used for the permissive voltage limits but as these are significantly
more onerous to calculate (and hence take significantly longer to calculate) and the
measurements are prone to significant fluctuations (measurement errors), the more
conservative prospective voltages are typically adopted. The calculation for the curves and
the initial loaded voltage limits are detailed in the EEA/NZ Guide to Power System
Earthing Practice.
Two location categories are used. Special location applies to any area where a significant
gathering of people may occur particularly situations where a high proportion of people
would not be wearing footwear. All other locations are considered to be normal locations.
10.6.8.3 Special location
(a)
Bare hands.
(b)
Bare feet.
(c)
A range of surface conditions.
Where the prospective step and touch voltage is below the limits in Figure 10.5(A) and
Figure 10.5(B), there is not considered to be a hazard during an earth fault.
10 0 0 0 0
Pe r m i s s i b l e p r o s p e c t i ve to u c h vo l t a g e l i m i t s ( V )
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Acceptable touch voltage limits have been developed for use in special locations assuming
the following:
Asphalt
10 0 0 0
Crushed rock
10 0 0 :- m
5 0 0 :- m
2 0 0 :- m
10 0 0
5 0 :- m
10 0
10
10
10 0
10 0 0
10 0 0 0
Fa u l t d u r a t i o n (m s)
NOTES:
1
For the curves a resistivity value of 5000 Ω-m has been used for crushed rock and 15000 Ω m for asphalt.
2
The dashed section of the asphalt curves indicates voltage limits for which the withstand voltage of the
asphalt layer may be exceeded.
FIGURE 10.5(A) TOUCH VOLTAGE LIMITS FOR SPECIAL LOCATIONS
EXCLUDING SHOE RESISTANCE
COPYRIGHT
99
AS/NZS 7000:2016
10 0 0 0 0
Pe r m i s s i b l e p r o s p e c t i ve s te p vo l t a g e l i m i t s ( V )
Crushed rock
10 0 0 0
10 0 0 :- m
5 0 0 :- m
2 0 0 :- m
5 0 :- m
10 0 0
10 0
10
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
10
10 0
10 0 0
10 0 0 0
Fa u l t d u r a t i o n (m s)
NOTES:
1
For the crushed rock curve a resistivity value of 5000 Ω-m has been used for crushed rock.
2
The curve for asphalt is not provided since the withstand voltage of the asphalt layer will most likely be
exceeded for the very high limits which would be associated with asphalt. Therefore the asphalt layer
should not be considered for step voltage limits.
FIGURE 10.5(B) STEP VOLTAGE LIMITS FOR SPECIAL LOCATIONS
EXCLUDING SHOE RESISTANCE
10.6.8.4 Normal location
Acceptable touch voltage limits have been developed for use in various normal locations
assuming the following:
(a)
Bare hands.
(b)
Impedance of 2000 Ω per shoe.
(c)
A range of surface conditions.
Where the prospective step and touch voltage is below the limits in Figure 10.6, there is not
considered to be a hazard during an earth fault.
COPYRIGHT
AS/NZS 7000:2016
100
Permissible prospective touch voltage limits ( V )
10 0 0 0 0
Asphalt
10 0 0 0
Crushed rock
10 0 0 :- m
5 0 0 :- m
10 0 0
2 0 0 :- m
5 0 :- m
10 0
10
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
10
10 0
10 0 0
10 0 0 0
Fa u l t d u r a t i o n ( m s )
NOTES:
1
For the curves a resistivity value of 5000 Ω-m has been used for crushed rock and 15000 Ω-m for asphalt.
2
The dashed section of the asphalt curves indicates voltage limits for which the withstand voltage of the
asphalt layer may be exceeded.
FIGURE 10.6 TOUCH VOLTAGE LIMITS FOR NORMAL LOCATIONS
INCLUDING 2000 Ω SHOES
The prospective tolerable step voltage limits are very high especially for the shorter earth
fault durations and may be well in excess of the withstand voltages for shoes. For this
reason, footwear impedance should be ignored when assessing step voltages and the
prospective tolerable limit curves from Figure 10.5(B) should be applied.
10.7 ELECTRICAL ASPECTS OF STAYWIRE DESIGN
10.7.1 General
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.
10.7.2 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 staywire 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.
COPYRIGHT
101
AS/NZS 7000:2016
There may be applications were a stay type insulator cannot be used. One example may be
the use of high tensile staywires 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.
10.7.3 Stay earthing for control of touch potentials
10.7.3.1 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 staywires 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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
(typically 3 m) or when in a broken stay wire state and also positioned such to maximize the
ability to insulate the stay to ground in the event of a fallen conductor directly onto the stay.
Stay insulators should be positioned a minimum of 1.5 m horizontally from a pole top to
reduce the risk of inadvertent contact between the pole and the earthed end of stay wire.
10.7.3.2 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 public.
Staywires, 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 staywire should also be considered. Fault currents shall be allowed to flow
to earth via the structure and its associated staywires, without damage being caused to the
staywire due to flow of fault current.
10.8 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 proximity to staywires and
their foundations shall be considered. Problems with dissimilar metals and galvanic
corrosion should be avoided.
COPYRIGHT
AS/NZS 7000:2016
S E C T I O N
102
1 1
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 based on the design working life of the
line.
11.2 ELECTRICAL REQUIREMENTS
11.2.1 Requirements applicable to all fittings
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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. In
addition, 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 operation and maintenance.
11.5 MECHANICAL REQUIREMENTS
Conductor termination fittings and all component fittings in insulator string assemblies
should be capable of transferring the maximum design load resulting from the load
combinations described in Table 7.3. The fittings should be selected taking into account
service conditions and required design life.
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.
COPYRIGHT
103
AS/NZS 7000:2016
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 (galvanic) corrosion of fittings or
conductor is minimized.
All ferrous materials, other than stainless steels, used in the construction of fittings shall be
protected against atmospheric 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 suitable wear resistant properties.
11.7 MATERIAL SELECTION AND SPECIFICATION
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
NOTE: When selecting metals or alloys for line fittings 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
11.8.1 General
The mechanical characteristics of insulator set fittings shall comply with the mechanical
strength requirements of AS 1154.1 or IEC 60471.
11.8.2 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 for the holding
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.
11.8.3 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 with AS 1154.1 or AS 1154.3 for helical fittings or equivalent International
Standards. Suspension and support fittings shall be designed as follows:
(a)
To achieve the mechanical strength nominated by the manufacturer or required by the
purchaser.
(b)
To achieve the slip strength nominated by the manufacturer or required by the
purchaser.
(c)
To 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.
COPYRIGHT
AS/NZS 7000:2016
104
11.8.4 Repair fittings
Repair fittings shall be designed and manufactured in accordance with AS 1154.3 or
equivalent International Standards. Repair fittings shall be designed to make good
conductors of which not more than 20% of the strands in the outermost layer have been
fractured or have other equivalent damage to that outermost layer. For low tension
conductors (less than 10% CBL) repair fittings can be used for not more than 40% of
fractured strands in the outermost layer. Repair fittings shall not be used to make good
damaged steel wires.
11.8.5 Spacers and spacer dampers
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 nominated sub-conductor separation;
(b)
be designed to minimize damage 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;
(e)
have an elastomer material which is semi-conducting and does not cause
electrochemical corrosion with the conductor; and
(f)
be installed in accordance with the recommendations of the manufacturers.
11.8.6 Vibration dampers
Vibration dampers shall be designed and manufactured in accordance with AS 1154.1 or
equivalent International Standards. Vibration dampers should be installed on all conductors
in accordance with Appendix Y. Vibration dampers shall be designed to minimize damage
to the conductors, suspension clamps and other hardware caused by wind induced Aeolian
vibration. Vibration dampers shall be installed in accordance with the recommendations of
the manufacturers.
11.8.7 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 elastomer inserts shall be selected to ensure the
elastomer components can withstand the steady state current rating.
The fittings shall be designed so the fitting is not prone to loosening because of thermal
ratcheting.
NOTE: Thermal ratcheting can occur when dissimilar metals are used together. An example is a
steel bolt 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.
11.8.8 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.
NOTE: Should moisture ingress occur in enclosed fittings such as termination fittings, the
moisture may freeze and expand and cause the fitting to loosen on the conductor or fracture the
fitting.
11.9 TEST REQUIREMENTS
All tests on overhead line fittings shall be carried out in accordance with the requirements
of AS 1154 and IEC 60471.
COPYRIGHT
105
AS/NZS 7000:2016
S E C T I ON 1 2
L I FE E X T E N SI 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 questions 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
This assessment shall consider whether:
(a)
The support structures are no longer safe to the public or maintenance personnel as
determined by further structural analysis and detailed assessment.
(b)
The support structures can economically be refurbished.
(c)
The overall line performance can be improved to an acceptable level by modification
or replacement of line components.
(d)
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
12.2.1 General
Current design requirements provide a useful ‘bench mark’ for existing construction, but it
is often appropriate to adopt the original design criteria consistent with the ‘fitness for
purpose’ for the overall network. Additional guidance is provided in AS ISO 13822.
The reasons for this approach are as follows:
(a)
Most asset owners have overhead lines which have undergone partial replacement of
individual supports since original construction.
(b)
Legislation has changed since original construction (i.e. the design requirements have
increased over time).
(c)
This approach will achieve a more favourable cost-benefit 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 structural loads to reflect the reduced remaining life of the assets. This provides for
all assets to have a similar reliability for the remaining life.
However consideration shall be given to providing 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.
COPYRIGHT
AS/NZS 7000:2016
106
12.2.3 Inspection
An inspection of the complete line shall be carried out as part of the evaluation process.
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.
12.2.4 Material properties
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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
entire population of similar components.
The statistical adjustment factor is usually based on the following:
(i)
The number of units.
(ii)
The coefficient of variation (COV) of structural property.
(iii) The minimum result from testing of structural property value.
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 either to verify the calculations and assumptions made or
to increase the load limit.
12.5 UPGRADING OF OVERHEAD LINE STRUCTURES
NOTE: Reference should be made to Appendix N for guidelines on the upgrading of structures for
service life extension.
COPYRIGHT
107
AS/NZS 7000:2016
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Reference should be made to Appendix M for guidelines on climbing and working at
heights on overhead lines.
COPYRIGHT
AS/NZS 7000:2016
108
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 ,
TELEC OMMUNICAT I ONS REPE ATER S)
14.1 SIGNS AND BANNERS AND TRAFFIC MIRRORS
14.1.1 General
This Clause applies to equipment rigidly attached to a pole.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
While the design of flagpoles is outside the scope of this Standard, the attachment of
banners to roadside poles is not uncommon for promoting special civic or community
activities. As the presence of banners may add appreciable lateral loads to these poles under
wind conditions, designers shall make allowance for increased loadings, where it is likely to
occur, e.g. 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.
14.1.2 Location
The location of banners shall comply with the following:
(a)
The positioning of a banner on a pole shall be not greater than 6 m above ground
level.
(b)
Double banners shall be located diametrically opposite one another and in a vertical
plane, which minimizes torsion effects with respect to any outreach arms.
14.1.3 Attachments
Where banners are attached at top and bottom to their mounting arms, the bottom
attachment shall be designed to release as soon as the design serviceability wind pressure is
exceeded.
The attachment of all banners shall be capable of retaining the banner on its top-mounting
arm at the ultimate design wind pressure for a maximum of 1 s.
14.1.4 Size of banners
The area of one face of any single banner shall not exceed 0.8 m 2 and the total face area of
banners on any single pole shall not exceed 2.0 m 2.
14.1.5 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 risk.
COPYRIGHT
109
AS/NZS 7000:2016
14.1.6 Wind loads on signs and banners
14.1.6.1 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:
⎛ C + Cdf × G ⎞
Fwf = ⎜ ff
⎟ pd × Af
b×κ
⎝
⎠
. . . 14.1
where
Fwf = total force on the banner (N)
Cff = a friction factor
= 0.024
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Cdf = a drag factor determined from Table 14.1
G
= unit mass of wet banner material kilograms per square metre (kg/m 2)
b
= dimension of banner at right angles to wind direction metres (m)
κ
= density of air, taken as 1.2 kg/m 3 kilograms per cubic metre
pd
= design wind pressure at the strength limit state Pascals (Pa)
Af
= area of (one) banner face square metres (m 2)
The mass per unit area of cloth materials, in a similar manner to paper, is usually quoted in
grams per square metre (g/m2). Making this substitution, substituting the numerical values
for Cff and κ, and puKz for pd, and converting to units consistent with Clause 1.5,
Equation 14.1 becomes—
⎡
⎛ 0.008Cdf wg ⎞ ⎤
Fwf = ⎢ 0.024 + ⎜
⎟ ⎥ pd K Z K T Af
b
⎝
⎠ ⎥⎦
⎣⎢
. . . 14.2
where
Fwf = total force on the banner (kN)
Cdf = a drag factor obtained from Table 14.1
wg = mass per unit area of wet flag material (g/m 2)
b
= dimension of banner at right angles to wind direction (m)
Af
= area of one face of the banner
and pd, Kz and KT are obtained from Appendix B for the strength limit state.
It is assumed that Fwf 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
A f /b
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: See Figure 14.1 for banner dimensions.
COPYRIGHT
AS/NZS 7000:2016
110
FIGURE 14.1 BANNER DIMENSIONS
14.1.6.2 Serviceability limit state
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
14.1.6.2.1 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.
14.1.6.2.2 Top attached banners
For top attached banners, Fwf is calculated from Equation 14.2 by substituting ps for pd,
when pd is obtained from Appendix B for the serviceability limit state.
14.1.6.2.3 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 (Fwf ) is calculated from
the following equation:
Fwf = 1.6 pd × Kz × KT × Af
. . . 14.3
where 1.6 is the drag factor for a sharp-edged flat surface and pd, Kz, KT and Af are as
defined previously.
14.2 COMMUNICATIONS CARRIER CABLES
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 subject to a full engineering assessment.
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.
COPYRIGHT
111
AS/NZS 7000:2016
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 needs to be
considered and appropriate safety measures deployed.
14.4 FLAGS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
For guidance on the design of flags see AS/NZS 4676 and AS/NZS 1170.2.
COPYRIGHT
AS/NZS 7000:2016
112
APPENDIX A
REFERENCE AND RELATED DOCUMENTS
(Normative)
A1 REFERENCED DOCUMENTS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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
1012
1012.11
Methods of testing concrete
Method 11: Determination of the modulus of rupture
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
1170
1170.4
Structural design actions
Part 4: Earthquake actions in Australia
1222
1222.1
1222.2
Steel conductors and stays—Bare overhead
Part 1: Galvanized (SC/GZ)
Part 2: Aluminium clad (SC/AC)
1531
Conductors—Bare overhead—Aluminium and aluminium alloy
1604
1604.1
Specification for preservative treatment
Part 1: Sawn and round timber
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 (phase-to-earth and phase-to-phase, above 1 kV)
Part 2: Application guide
2067
Substations and high voltage installations exceeding 1 kV a.c.
2159
Piling—Design and installation
2209
Timber—Poles for overhead lines
2650
Common specifications for high-voltage switchgear and controlgear standards
(IEC 60694, Ed. 2.2(2002) MOD)
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
COPYRIGHT
113
AS
3995
Design of steel lattice towers and masts
4100
Steel structures
4435
4435.4
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
5804
High-voltage live working (series)
6947
Crossing of waterways by electricity infrastructure
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
4435.1
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AS/NZS 7000:2016
AS/NZS
1170
1170.0
1170.2
1170.3
1170.5
Structural design actions
Part 0: General principles
Part 2: Wind actions
Part 3: Snow and ice actions
Part 5: Earthquake actions—New Zealand
1328
1328.1
Glued laminated structural timber
Part 1: Performance requirements and minimum production requirements
1559
Hot-dip galvanized steel bolts and associated nuts and washers for tower
construction
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
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 (series)
3675
Conductors—Covered overhead—For working voltages 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
Electric
cables—Aerial
bundled—Polymeric
6.35/11(12) kV and 12.7/22(24) kV
Part 1: Metallic screened
Part 2: Non-metallic screened
insulated—Voltages
Conductors—Covered overhead—For working voltages 6.35/11(12) kV up to
and including 19/33(36) kV
COPYRIGHT
AS/NZS 7000:2016
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AS/NZS
3835
114
Earth potential rise—Protection of telecommunications network users,
personnel and plant (series)
4058
Precast concrete pipes (pressure and non-pressure)
4065
Concrete utility services poles
4435
4435.2
Insulators—Composite for overhead power lines—Voltages greater than
1000 V a.c.
Part 2: 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
60479
60479.1
Effects of current on human beings and livestock
Part 1: General aspects
AS ISO
13822
Basis for design of structures—Assessment of existing structures
(ISO 13822:2001, MOD)
12494
Atmospheric icing of structures
AS IEC
60720
Characteristics of line post insulators (IEC 60720, Ed. 1.0 (1981) MOD)
HB
88 (CJC2)
Unbalanced high voltage power lines: Code of practice for the mitigation of
noise induced into paired cable telecommunications lines from unbalanced high
voltage power lines
101 (CJC5) Coordination of power and telecommunications—Low frequency induction
(LFI): Code of practice for the mitigation of hazardous voltages induced into
telecommunications lines
102 (CJC6) Coordination of power and telecommunications—Low frequency induction
(LFI)
331
Overhead line design
NZS
3101
3101.1
Concrete structures standard
Part 1: The design of concrete structures
3404
3404.1
Steel structures standard
Part 1: Materials, fabrication, and construction
3603
Timber structures standard
6869
Limits and measurement methods of electromagnetic noise from high voltage
a.c. power systems, 0.15—1000 MHz
NZECP
34
New Zealand Electrical Code of Practice for Electrical Safety 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
COPYRIGHT
115
AS/NZS 7000:2016
NZECP
NZCCPTS Noise Interference Guide
EEA/NZ
Safety Manual—Electricity Industry (SM-EI) (Parts 1 & 2)
Use of Helicopters in Power Company Work (Guide)
Use of Personal Fall-Arrest Systems (Guide)
Safety Management of Power Line Waterway Crossings (Guide)
Mobile Plant Use—ESI Employees (Guide)
Power System Earthing Practice (Guide)
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
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Doc 025 EG-0 Power System Earthing Guide, Part 1: Management Principles
NENS 04
National guidelines for safe approach distances to electrical and mechanical
apparatus
NENS 05
National fall protection guidelines for the electricity industry
IEC
60372
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
60652
Loading tests on overhead line towers
60794
60794-4
Optical fibre cables
Part 4: Sectional specification—Aerial optical cables along electrical power
lines
60826
Design criteria of overhead transmission lines
60865
60865-1
Short-circuit currents—Calculation of effects
Part 1: Definitions and calculation methods
61466
Composite string insulator units for overhead lines with a nominal voltage
greater than 1000 V
Part 2: Dimensional and electrical characteristics
61466-2
IEC
TR 60575
TR 61597
ISO
14713
Thermal-mechanical performance test and mechanical performance test on
string insulator units
Overhead electrical conductors—Calculation methods for stranded bare
conductors
Zinc coatings—Guidelines and recommendations for the protection against
corrosion of iron and steel in structures (series)
COPYRIGHT
AS/NZS 7000:2016
116
EN
1993
Design of steel structures
Eurocode 3 1993-3-1 Part 3-1: Towers, masts and chimneys—Towers and masts
1994
Eurocode 4 1994-2
Design of composite steel and concrete structures
Part 2:
General rules and rules for bridges
50341
50341-1
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
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
TB291
Guidelines for meteorological
topographical effects
icing
models,
statistical
methods
ANSI
TIA-222G
Structural Standards For Antenna Supporting Structures and Antennas
IEEE
80
Guide for Safety in AC Substation Grounding
691
Guide for Transmission Structure Foundation Design and Testing
738
Calculating
Conductors
the
Current-Temperature
Relationship
of
Bare
and
Overhead
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 Electric, Magnetic, and
Electromagnetic Fields (Up To 300 Ghz)
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: Soil strength and consolidation tests—Determination of the
penetration resistance of a soil—Standard penetration test
(SPT)
1657
Fixed platforms, walkways, stairways and ladders—Design, construction and
installation
1798
Lighting poles and bracket arms—Recommended dimensions
2560
Sports lighting (series)
2979
Traffic signal mast arms
60038
Standard voltages
AS/NZS
1170
1170.1
Structural design actions
Part 1: Permanent, imposed and other actions
1252
High strength steel bolts with associated nuts and washers for structural
engineering
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
117
AS/NZS 7000:2016
AS/NZS
1768
Lightning protection
NZS
3115
Specification for concrete poles for electrical transmission and distribution
4203
Code of practice for general structural design and design loadings for
buildings—Vol 1
1170
1170.5
Structural design actions
Part 5 Earthquake actions—New Zealand
60287
60287-3-1
Electric cables—Calculation of the current rating
Part 3-1: Sections on operating conditions—Reference operating conditions
and selection of cable type
IEC
60050
60050-441
60050-466
60050-471
60050-601
60050-604
International Electrotechnical Vocabulary
Chapter 441: Switchgear, controlgear and fuses
Chapter 466: Overhead lines
Chapter 471: Insulators
Chapter 601: Generation, transmission and distribution of electricity—
General
Chapter 604: Generation, transmission and distribution of electricity—
Operation
60724
Short-circuit temperature limits of electric cables with rated voltages of 1 kV
(U m = 1,2 kV) and 3 kV (U m = 3,6 kV)
TR 60797
Residual strength of string insulator units of glass or ceramic material for
overhead lines after mechanical damage of the dielectric
60909
Short-circuit currents in three-phase a.c. systems (series)
61109
Insulators for overhead lines—Composite suspension and tension insulators
for a.c. systems with a nominal voltage greater than 1 000 V—Definitions,
test methods and acceptance criteria
61211
Insulators of ceramic material or glass for overhead lines with a nominal
voltage greater than 1 000 V—Impulse puncture testing in air
61467
Insulators for overhead lines—Insulator strings and sets for lines with a
nominal voltage greater than 1 000 V— AC power arc tests
TS 61774
Overhead lines—Meteorological data for assessing climatic loads
62219
Overhead electrical conductors—Formed wire, concentric lay, stranded
conductors
ISO
1461
Hot dip galvanized coatings on fabricated iron and steel articles—
Specifications and test methods
9001
Quality management systems—Requirements
NZECP
35
New Zealand Electrical Code of Practice for Power Systems Earthing
EEANZ
Guide to Work on De-Energized Distribution Overhead Lines
EN
1993
Design of steel structures
Eurocode 31993-1-1 Part 1-1: General rules and rules for buildings
COPYRIGHT
AS/NZS 7000:2016
118
ESAA
D(b)5*
Current rating of bare overhead line conductors
EANSW
High Voltage Earth Return for Rural Areas
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
A3 ADDITIONAL READING MATERIAL
1
BURGESS, S., SALINGER, J., TURNER, R. and REID, S., Climate Hazards and
extremes – Taranaki region. High winds and tornadoes. NIWA report
WLG2007-048, 2007, 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
CIGRE STUDY TB256, Current Practices regarding frequencies and magnitude of
high intensity winds.
7
DURAŇONA, V., STERLING, M. and BAKER, C., ‘An analysis of extreme nonsynoptic winds’, Journal of Wind Engineering and Industrial Aerodynamics, 95,
2007, 1000–1027.
8
ESAA EG-1(1997), ESAA Substation Earthing Guide.
9
GIBBS, H., Inquiry into Community Needs and High Voltage Transmission Line
Development, published by New South Wales Government, 1991.
10
Guidelines for the Management of Electricity Easements, ISSC20, Electricity
Association of NSW, November 2001.
11
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.
12
KIESSLING, F., NEFZGER, P., NOLASCO, J.F. and KAINTZYK, U., Overhead
Power Lines (planning design construction), ISBN 3-540-00297-9, 2013, pp. 162–
163.
13
MORGAN, V.T., Thermal Behaviour of Electrical Conductors, Steady, Dynamic and
Fault-Current Ratings, John Wiley and Sons Inc., Brisbane, 1991.
14
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.
15
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.
16
NIWA report WLG2007-71, REID, S.J., ‘Wind speeds for engineering design’ New
Zealand Engineering, March 1, 1987, pp 15–18.
*
Available to members through Energy Networks Australia (ENA).
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
119
AS/NZS 7000:2016
17
REID, S. and TURNER, R., Gust speeds for downslope sites using 2D modelling.
Journal of Wind Engineering and Industrial Aerodynamics, 2008.
18
ROSS, H.E. et al, Recommended procedures for the safety performance evaluation of
highway safety features, NCHRP Report 350, National Cooperative Highway
Research Program, National Academy Press, Washington D.C., 1993.
19
SMOOT, A.W. and BENTEL, C.A., Electric Shock Hazard of Underwater Swimming
Pool Lighting Fixtures, IEE Transactions of Power Apparatus and Systems, Vol. 83,
September 1964, pp 945–964.
20
TAIT, A., and REID, S., An analysis of extreme high winds in the Gisborne district,
NIWA report WLG2007-25, 2007, p30.
21
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.
22
HOLMES, J.D., Physical modelling of thunderstorms downdrafts by wind tunnel jet,
2nd AWES Workshop 20–21 February 1992, Monash University, Clayton, Victoria.
23
LETCHFORD, C.W. and ILLIDGE, G.C., Topographical effects in simulated
thunderstorm downdrafts by wind tunnel jet, 7th AWES Workshop, 28–29 September
1998, Auckland, New Zealand.
24
PANEER SELVAM, R. 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.
25
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.
26
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, pp
252–258.
COPYRIGHT
AS/NZS 7000:2016
120
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 is similar.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 B1 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 Figure B1, designs are to provide only for winds from synoptic events
using multipliers from AS/NZS 1170.2, together with ‘conventional’ span reduction factors
as provided in the following sections.
Zone II—(i.e. inland Australia) designs 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 Figure B1, both events can occur and designs are to provide for both
types of events. In regions C and D, as defined in AS/NZS 1170.2, the design downdraft
wind is not applicable.
NOTE: Figure B1 is not intended to show the zoning system for the magnitude of the wind gust
speed—just the types of event producing the extreme gusts required to be considered for design.
Reference should be made to AS/NZS 1170.2 for the relevant return period wind speeds as
defined in Section 6.
COPYRIGHT
121
AS/NZS 7000:2016
We i pa
DA RWIN
M c D o n n e l C re e k
M o reto n
C o o k tow n
Ca ir ns
B ro o m e
20 0 k m
C royd o n
O ns l ow
Zo n e II - C o nve c ti ve d ow n d raf ts o n l y
Ca r n a r vo n
20 0 k m
Tow nsv i l l e
B owe n
M a c k ay
Ro c k h a m pto n
B u n d a b e rg
M a r y b o ro u g h
25˚
BRISBANE
G raf to n
C of f s H a r b o u r
G e ra l d to n
PERT H
SY D N E Y
20 0 k m
A D EL A ID E
M EL B O U R N E
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Zo n e III - S y n o pti c a n d c o nve c ti ve
Zo n e I - S y n o pti c w i n d s o n l y
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 and downslope high
velocity winds occur in which these structures are also vulnerable.
Wind zones for the North and South Islands of New Zealand are shown in Figure B2.
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AS/NZS 7000:2016
122
FIGURE B2 WIND REGIONS FOR NEW ZEALAND
B3 SYNOPTIC WIND REGIONS (AUSTRALIA ZONE I AND ZONE III AND ALL
ZEALAND REGIONS)
All structures shall be designed for a peak gust regional wind speed for the relevant return
period wind as defined in AS/NZS 1170.2.
Cyclonic wind amplification factors Fc and Fd 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.
COPYRIGHT
123
AS/NZS 7000:2016
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. Variations
in wind loading may be required to take into account variations in terrain, topography and
exposure along the length of line. The site design wind speed is the basic regional wind
speed modified for the effects of the topography and terrain that the line traverses.
AS/NZS 1170.2 provides regional wind speeds for various return periods.
The design site wind speed shall be taken as—
. . . B1
Vsit,β = VR Md Mz,cat Ms Mt
where
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Mz,cat = gust wind speed multiplier for terrain category
See AS/NZS 1170.2, for all regions use Table 4.1(A)
Md
at
height z.
wind direction multiplier. See AS/NZS 1170.2
Ms
= shielding multiplier. See AS/NZS 1170.2
Mt
= topographic multiplier for gust wind speed. See AS/NZS 1170.2
VR
= basic regional wind velocity for the region corresponding to the selected
return period wind. See AS/NZS 1170.2
Designers should be aware that changing land usage may alter the terrain category.
z for the conductors shall be taken as the average conductor height or the average
attachment height.
z for structures under 50 m in height may be taken at the 2/3 structure height or at the
centre of each panel in lattice towers.
Md < 1.0 may be applied when determining design loads for sections of lines.
Ms is normally taken as 1.0.
B4 DOWNDRAFT WIND REGIONS (AUSTRALIA ZONE II AND ZONE III AND
NEW ZEALAND REGIONS A7)
B4.1 General
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.
COPYRIGHT
AS/NZS 7000:2016
124
B4.2 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 associated with a hail column. The cold air column falls vertically from
great height and strikes the ground, causing the wind draft to radiate from the impact site.
The translational velocity of the storm is added vectorially to the radial wind velocity. 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 render the application of the synoptic wind based
span reduction factors inappropriate.
A span reduction factor shall be applied as provided in Figure B6.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 approximately 15 m above ground as a result of the localized
influence of vegetation and ground surface roughness.
The return periods in AS/NZS 1170.2 Table 3.1 are appropriate to individual structures
affected by either wind types. The return periods will not reflect the probability of a
relatively small scale convective downdraft event crossing a long overhead line. However,
where the scale of the event is large (e.g. cyclones), the return period reflects the
probability that some structures will be subjected to the maximum wind speeds.
AS/NZS 1170.2 regions C and D are based on cyclonic wind data. Region B boundaries
reflect the transition between the cyclonic and non-cyclonic zones. At this time there is no
evidence that small scale convective type events, such as downdrafts, are more severe in
regions B, C or D. Therefore, AS/NZS 1170.2 wind speeds for these regions shall not be
used for the downdraft wind design. Region A wind speeds shall be used for downdraft
wind design.
In keeping with observation on the effects of event scale, it is recommended that in
region B until more definitive data is available, designers should select one higher level of
line security for convective winds to achieve comparable overhead line reliability in all
zones.
Wind pressures are to be calculated as for synoptic winds except for modification to Mz and
Mt factors as provided below.
Terrain-Height Multiplier Mz,cat shall be calculated in accordance with Figure B3 and the
following rules:
Height (m)
Mz,cat
0–50
1.0
50–100
Above 100
1.0 −
0.5 × (H - 50)
50
0.5
COPYRIGHT
. . . B2
125
AS/NZS 7000:2016
D ow n d r a f t M z ,c a t
140
120
H e i g h t [m]
10 0
80
60
40
20
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
0
0. 2
0.4
0.6
0.8
1
M z ,c a t
FIGURE B3 TERRAIN-HEIGHT MULTIPLIER FOR CONVECTIVE DOWNDRAFTS
Topographic multiplier Mt,downdraft shall be calculated in accordance with the following:
Mt,downdraft = 0.5 + 0.5Mt,synoptic
. . . B3
B4.3 Tornadoes (applies to all high security/high reliability overhead lines only such
as regional transmission interconnectors)
B4.3.1 General
Evidence exists of the occurrence of tornadoes in several regions around Australia and
New Zealand of an intensity <EF3 (Enhanced Fujita Tornado Scale) classification with
maximum velocities in the 45–74 m/s range. Most are either EF0 or EF1, i.e. maximum
velocities <50 m/s. No evidence currently exists of either EF4 or EF5 tornadoes having
occurred in Australia or New Zealand. Tornadoes can be considered very rare events at
particular locations and should not be considered in normal range of overhead line designs.
However, two regions of New Zealand (the coastal zones near New Plymouth and
Greymouth) are known to experience on average one tornado a year.
B4.3.2 High security and high reliability overhead lines
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 rotational (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.
Tornadoes crossing lines between supports are unlikely to cause any structural damage but
may cause 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.
COPYRIGHT
AS/NZS 7000:2016
126
B5 WIND PRESSURES
B5.1 General
The design pressure qz shall be specified or calculated as follows:
qz = 0.6 Vsit,2 β × 10 −3 (kPa)
. . . B4
B5.2 Wind pressures on lattice steel towers
For lattice towers that are essentially square or rectangular in plan the force in the direction
of the wind on the whole tower section under consideration shall be calculated as follows:
. . . B5
Fsθ = qzCdA
where
A = is the projected area of one face of the structure section under consideration in
a vertical plane along the face
Cd = drag force coefficient for each panel
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
TABLE B1
LATTICE TOWER PANEL DRAG COEFFICIENTS
FOR MULTIPLE FRAMES AND SINGLE FRAMES
Solidity factor
δ
Multiple frames (Square tower)
Single frames
C d 0°
C d 45°
CD
Shielding η
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—
Fsθ = qz [Cd1 (A1 + ηA3) kθcos2 θ + Cd2 (A2 + ηA4) kθsin2θ]
. . . B6
where
A1, A3 and A2, A4 are projected areas on longitudinal and transverse faces respectively
Cd = drag force coefficient for single frames (panels) (see Table B1)
η
= shielding factor (see Table B1)
kθ
= factor for angle of incidence θ of wind to frames
(calculated by the equation)—
kθ = 1 + k1 k2 sin2(2θ)
. . . B7
where
k1
= 0.55
k2
= 0.2 for δ ≤ 0.2
k2
= δ for 0.2 < δ ≤ 0.5
k2
= 1 − δ for 0.5 < δ ≤ 0.8
k2
= 0.2 for 0.8 < δ ≤ 1.0
COPYRIGHT
127
AS/NZS 7000:2016
Where ancillaries such as antennae, mounting frames, cable runways, signage and banners
that have significant area, are attached to a tower, they should be included in the calculated
force using the appropriate Cd, area and shading factor from Australian Standards and
component manufacturer’s information.
There is some variation in recommended Cd factors for single and multiple frames between
the various national codes. The approach used in Eurocode 3 1993-3-1 provides detailed
procedures for calculation of drag coefficients for rectangular (in plan) towers for different
angle of incidence of wind. The Eurocode 3 1993-3-1 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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. (See Figure B4.)
M
T
W in d
W
a
D
Fm
FIGURE B4 FORCES ON A MEMBER
The force is determined by the following equation:
F m = Cf qz Am cos2(α)
. . . B8
where
F m = resultant force on the member
qz
= dynamic pressure at the member mid height
A m = simplified member area – length × width
Cf
= force coefficient
= angle members Cf = 1.6
= round members Cf = 1.0
α
= angle between wind velocity vector and the normal to the member axes
COPYRIGHT
AS/NZS 7000:2016
128
From 3D geometry, the resultant force direction vector can be determined using the vector
products:
T = W×M
D = T×M
W = wind velocity vector
M = member axis vector
T = vector perpendicular to the wind-member plane
D = resultant force direction vector
Angle a can be calculated from the scalar product of the wind direction and resultant force
direction vectors:
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
cos ( a ) =
WD
W D
. . . B9
The resultant force components in the global coordinate directions (X, Y and Z) can be
finally calculated by multiplying the resultant force value by the normalized direction
vector.
B5.3 Wind pressure on poles
Due consideration shall be taken of the affect on the aerodynamic shape factor Cfig for poles
due to the attachment of all ancillaries.
Significant attachments to circular cross-sections such as ladders, pipes, etc., will induce
aerodynamic separation and in this case Cd = 1.2.
The aerodynamic shape factor Cfig shall be determined for specific elements, surfaces or
parts of surfaces in accordance with AS/NZS 1170.2.
NOTE: Drag coefficients for different types of poles are given in AS/NZS 1170.2.
B5.4 Wind forces on conductors
Wind force perpendicular to conductors shall be calculated as follows:
Fc = qz × Cd × L × d × SRF × cos2α (kN)
. . . B10
where
Cd = drag coefficient of conductor. This is assumed to be equal to 1 in the absence
of more accurate information.
NOTE: 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 wind span length for SRF or section length for TSRF(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.
COPYRIGHT
129
AS/NZS 7000:2016
When determining wind pressure on conductor for conductor tension calculations, the TSRF
for the related tension section shall be used.
qc = qz × Cd × TSRF × cos2α
. . . B11
where
qc
=
TSRF=
conductor tension related wind pressure
tension section reduction factor (multiple spans)
The tension section length for TSRF calculations is the overhead line length between the
related strain supports where the suspension supports provide a sufficient longitudinal
flexibility to enable conductor tension equalization between the strain supports.
B5.4.1 Span reduction factor (SRF and TSRF) for synoptic wind regions
For regions governed by synoptic winds Figure B5 applies. The curve in Figure B5 is based
on the following relationship:
. . . B12
1.10
1.00
0.90
SRF or TSRF
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
SRF = 0.59 + 0.41e
⎛ −L ⎞
⎜
⎟
⎝ 210 ⎠
0.80
0.70
0.60
0.50
0.40
0
100
200
300
400
500
600
700
800
900
1000
W I N D S PA N o r S EC T I O N LE N GT H , m
FIGURE B5 SRF OR TSRF FOR SYNOPTIC WIND
B5.4.2 Span reduction factor (SRF and TSRF) for downdraft wind regions
For regions governed by downdraft wind Figure B6 applies. The curve of Figure B6 is
based on the following expressions:
For spans, L ≤200 m
SRF = 1.0
For spans, L >200 m
SRF = 1.0 −
( L − 200)
0.3125
1000
. . . B13
For tension calculations on tension sections greater than 1500 m, the synoptic wind shall be
used instead of the downdraft wind.
COPYRIGHT
AS/NZS 7000:2016
130
1.10
1.0 0
SRF or TSRF
0.9 0
0. 8 0
0.70
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
0.6 0
0. 50
0.4 0
0
20 0
400
600
800
10 0 0
W I N D S PA N o r S E C T I O N LE N GT H , m
FIGURE B6 SRF OR TSRF FOR DOWNDRAFT WIND REGIONS
B5.4.3 Conductor tensions
When considering the conductor loads applied to strain structures, the influence of the
change in line direction and the angle of incidence of the wind to the conductors shall be
taken into consideration.
B5.5 Wind forces on insulators and fittings
Force on insulators and fitting assemblies shall be considered and is given by the following
expression:
Fi = qz × CdA
. . . B14
where
Cd = 1.2
A
= projected area of insulators and fittings in true length normal to wind (m²)
(see Figure B7)
These forces shall be considered to act on the attachment point on the support in the wind
direction.
COPYRIGHT
131
AS/NZS 7000:2016
Attachment point
True length
F i = q z .C d A
View along line
Projected area is shaded
View transverse to line
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
FIGURE B7 PROJECTED AREA OF INSULATOR STRINGS
COPYRIGHT
AS/NZS 7000:2016
132
APPENDIX C
SPECIAL FORCES
(Informative)
C1 GENERAL
This Appendix sets out requirements to be considered in overhead line design regarding
special forces that may be encountered on some lines.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 consider
these 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
t1**
Force 2 at time
t2**
Force 3 at time
t3**
Horizontal
displacement
Pinch force, Fpi
(tensile force in
the conductor)
when the subconductors clash
or reduce their
distance without
clashing
Short-circuit
tensile force, Ft
due to swing-out
in the conductor
bundle during or
at the end of the
short-circuit
current flow
Short-circuit
drop force, Ff
(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, Ft
due to swing-out
in the conductor
during or at the
end of the shortcircuit current
flow
Short-circuit
drop force, Ff
(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 t1, t2 and t3 are derived from the total short-circuit duration.
**
The above forces, Fpi, Ft and Ff 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.
COPYRIGHT
133
AS/NZS 7000:2016
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The simplified approach depends on general data such as span length, everyday tension
(EDT), 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.
(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 five to ten spans from the substation. Usually,
only one span is affected by the excessive swinging and one or two supports adjacent
to the substation are subjected to the mechanical overloads from short-circuits.
(f)
Only the two-phase short-circuit current should be checked.
The reduction of short-circuit current with time should also be taken into account according
to the electrical characteristics to the system. The primary fault clearing time should be
used.
The load combinations required to assess and design structures able to withstand shortcircuit forces is of considerable interest, in addition the load factors taken into account on
the generated tensile forces due to short-circuit are important so as not to overestimate 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 standards available which account for a true or
reasonable combination of short-circuit and wind loads. Therefore, it would be sufficient to
consider a 25% ultimate wind effect in the load combination related to short-circuit
loadings.
In practice, short-circuit loadings are treated as dynamic loadings due to their short time
duration. In the simplified approach, this load is treated as an ‘exceptional load’ and a load
factor of 1.25 is recommended. In the case of short impulsive loads for which large stress
rates occur, structural materials experience a delayed plastic flow phenomenon or elasticity
that results in a temporary increase in strength (yield point).
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—
For short-circuit load φRn > Wn + 1.25Ft + 1.1Gs + 1.25Gc + 1.25Fsc*
. . . C1
Ft tensions for conductors not in short-circuit on one of the 3-phases should be based on
temperature corresponding to everyday load condition with a nominal wind pressure of
0.25 times the ultimate design wind pressure.
Fsc* short-circuit tensions are the maximum of the Ft, Ff and Fpi tensions from the
simplified calculation methods of IEC 60865-1 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.
COPYRIGHT
AS/NZS 7000:2016
134
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
C4.1 General
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Wind loadings are usually the main 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 resonant 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 1170.4 or NZS 1170.5 for appropriate general design
provisions. The ultimate limit state earthquake return periods to be used to determine the
required annual probability of exceedance, are the same as the minimum design wind return
periods given in Table 6.1, and are to be used to determine the probability factor
(AS 1170.4 Table 3.1) or the return period factor (NZS 1170.5 Table 3.5), as applicable. In
addition the following specific provisions for overhead lines should be considered.
C4.2 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 liquefaction, should recognize 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.
In general, pole and tower structures have proven not to be susceptible to damage from
earthquake shaking motions.
Structures of the following types however, should 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 least 50% of the contributing mass (including 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).
COPYRIGHT
135
AS/NZS 7000:2016
Pole structures with a longer fundamental period and located in deep alluvial soils are often
sensitive to the amplification effects of ground motion. This should be taken into account
by the spectral shape factor during the selection of the particular site subsoil class.
C4.3 Seismic mass
The seismic mass of the pole/tower structure should include 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. The vertical conductor
loads should be considered in determining the overall seismic mass.
C4.4 Fundamental period of structure (T1)
The fundamental period can be determined using the Rayleigh method in NZS 1170.5 or by
computer analysis. Alternative calculation methods can be found in ANSI/TIA-222G.
The ultimate limit state earthquake return period should be identified in accordance with
Table 6.1.
C4.5 Ductility factor
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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
C4.6 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 ff =
Ec
⎛
⎞
( wL) 2
⎜1 +
AE c ⎟⎟
3
⎜
(12 H )
⎝
⎠
. . . C2
If this is to be modelled as a horizontal spring, then the horizontal component of the change
in cable tension due to earthquake displacement should be taken as—
H earthquake = H +
Δ cos 2 α Ac E ff
L
. . . C3
where
Ac
= the cross-sectional area of the conductor of cable, square millimetres (mm 2 )
Ec
= the modulus of elasticity of the conductor or cable
Eff = the effective modulus of elasticity, in megapascals (MPa)
H
= the tensile strength in the conductor or cable, in Newtons (N)
L
= span length, in metres (m)
w
= conductor or cable unit weight, in Newtons per metre (N/m)
α
= the angle of the cable to the horizontal (degrees)
Δ
= horizontal seismic displacement of the conductor attachment (m)
COPYRIGHT
AS/NZS 7000:2016
136
If the horizontal distance between the structure base and stay anchor point exceeds 300 m,
out-of-phase excitation of the anchor point should be included in the analysis.
C4.7 Methods of analysis
C4.7.1 Equivalent static force method
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 not 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.
On a lattice tower, a section should be considered the distance between vertical leg
connections but not exceeding 15 m.
NOTES:
1 The mass of stays is excluded from determining mass irregularities.
2 Antenna mounts, platforms, torque arms and cross-arms should not be considered a
stiffness irregularity.
C4.7.2 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.
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).
C4.7.3 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 exceeds 300 m (out of plane movements are included in the analysis) or
exceeds the height requirements for a modal analysis.
COPYRIGHT
137
AS/NZS 7000:2016
C4.8 Combination of effects
A combination of effects of orthogonal actions should be applied to the structure to account
for the simultaneous effects of shaking in the two perpendicular directions using either—
(a)
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; or
(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.
C4.9 Second order effect analysis (Pδ)
Second order effects (Pδ) need not be considered when δM/Mo < 0.10 where δM is the
overturning effect due to second order effects and Mo is the first order overturning moment.
Second order effects should be considered for all guyed structures.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
C4.10 P-Δ Effects
Second order effects (PΔ) 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 to face ratio (h/W) is less than 10.
A rational analysis method which takes into account the post elastic deflections of the
structure should be used to determine the PΔ effects.
C4.11 Vertical seismic response
The structures should be designed to remain elastic under both positive and negative
vertical acceleration. This should be considered to act non-concurrently with the horizontal
seismic response.
C4.12 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=
g.C (T ).T1 2 S p
. . . C4
( 4π 2 k μ )
where
Δ
= the seismic displacement at centre of mass (m)
kμ
= ductility coefficient
g
= 9.81 m/s2
T1
= the fundamental period of the structure (s)
C(T) and Sp are factors in NZS 1170.5
A further scaling factor should be applied to account for P-Delta effects (if relevant).
COPYRIGHT
AS/NZS 7000:2016
138
C4.13 Liquefaction
Liquefaction of loose saturated, cohesion-less soils (sands, silts and loose sandy gravels)
during strong seismic tremors should be taken into consideration in the route selection of
lines.
The consequences of liquefaction should 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 should be consistent with the other performance requirements for
the pole or line section.
C4.14 Holding-down bolts
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Where base plate mounting of structures are used, holding-down bolts should provide a
minimum net vertical uplift reaction under design earthquake conditions not less than 50%
of the dead load reaction.
C5 MINING SUBSIDENCE
C5.1 General
Where overhead lines are located in areas subject to underground coal mining the impact of
ground subsidence and horizontal displacement of soil strata should 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.
C5.2 General design provisions
Pole lines are generally not sensitive to mining subsidence, except in the case of stayed
poles or unless electrical clearances are breached.
Transmission line towers however, can be affected 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.
However, in the case of older coal mines, these pillars 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 progressively to ‘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.
COPYRIGHT
139
AS/NZS 7000:2016
APPENDIX D
SERVICE LIFE OF OVERHEAD LINES
(Informative)
D1 GENERAL
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 design guidelines 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 associated 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 from the pumping action caused
by 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.
COPYRIGHT
AS/NZS 7000:2016
140
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
fire-resistant materials. The post-fire strength and durability of poles should be assessed by
a competent person.
D3.7 Concrete poles
Service life considerations for concrete poles include the following:
(a)
Environmental High quality concrete exposed to normal ‘arid’ or ‘temperate’
conditions would be regarded as having a long service life. This Standard 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%.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTE: See Appendix O for test method.
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. Consideration should
be given to the capping of the base of hollow spun concrete poles to prevent capillary
action of 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.
Pre-stressed concrete poles can be used where cracking needs to be minimized.
D3.8 Timber poles
The values of service life given in Table D4 assume that the poles are subject to a
systematic program of inspection, at least as often 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 these has been made in the design provisions
of Appendix F by the use of pole degradation (kd) factors.
Where supplementary maintenance such as the provision of diffusion preservatives or
specific protection systems for termites are provided, the service life of poles will be
longer.
The exposure classifications in Table D1 refer to generalized conditions, and it should be
kept in mind that timber poles may be susceptible to localized microclimatic effects.
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 exposure risk.
COPYRIGHT
141
AS/NZS 7000:2016
While New Zealand has three known native termite species, field experience indicates they
do not pose a concern to timber poles.
DA RWIN
Ca ir ns
B ro o m e
Tow nsv i l l e
Po r t H e d l a n d
Mount Isa
Alice Springs
R o c k h a m pto n
C h a r l ev i l l e
BRISBA N E
N a r ra b r i
Kalgoorlie
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
G e ra l d to n
Dubbo
Mildura
Albur y
PERT H
A l ba ny
A D EL A ID E
M o u nt G a m b i e r
M EL B O U R N E
N ewc a s tl e
SY D N E Y
CA N B ER R A
Bega
L EG EN D :
=
=
=
=
=
=
Ve r y h i g h
High
M o d e rate
Low
Ve r y l ow
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/m2 on steel less than 2 mm thick,
450 g/m2 on steel between 2 mm and 5 mm thickness and 600 g/m2 on steel over 5 mm
thick. The expected life for a given coating mass (years) in different atmospheric
environments is shown in Table D2.
COPYRIGHT
AS/NZS 7000:2016
142
TABLE D1
ABOVE-GROUND ENVIRONMENTAL EXPOSURE CLASSIFICATION
(AUSTRALIA)
Climatic zone
(see Figure D2)
Geographic region (1)
Industrial proximity (2)
Exposure class (3)
Non-industrial
A1
Industrial
B1
Near-coastal
—
B1
Coastal
—
B2
Non-industrial
A2
Industrial
B1
Near-coastal
—
B1
Coastal
—
B2
Non-industrial
B1
Industrial
B2
Near-coastal
—
B1
Coastal
—
B2
Any
—
C
Inland
Arid
Inland
Temperate (4)
Inland
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Tropical
(See Note 4)
NOTES:
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
purposes the regions are defined in Australia as follows:
(a)
Inland—greater than 50 km from coast.
(b)
Near-coastal—between 1 km and 50 km from coast.
(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 as non-industrial if it is greater than 3.0 km from industrial plants
that discharge air pollutants such as carbon dioxide (CO 2 ), sulphur dioxide (SO 2 ) and sulphur
trioxide (SO 3 ), 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 shoreward for 500 m from the high-tide mark. The near-coastal
region to which Exposure Class B1 applies extends from there to the boundary of the A2 region.
Active volcanic/geothermal areas may be regarded as Exposure Class C.
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
143
FIGURE D2 CLIMATIC ZONES FOR AUSTRALIA
COPYRIGHT
AS/NZS 7000:2016
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AS/NZS 7000:2016
144
FIGURE D3 (in part) NEW ZEALAND REGIONS FOR EXPOSURE CLASSES A2 and B1
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
145
AS/NZS 7000:2016
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.
COPYRIGHT
AS/NZS 7000:2016
146
TABLE D2
SUGGESTED RANGE OF NOMINAL ABOVE-GROUND SERVICE
LIFE OF STEEL STRUCTURES AND CONCRETE POLES
Suggested nominal service life (years)
Galvanized steel (4)
Exposure class
200 g/m
A1
60–100+
A2
400 g/m
2(1)
Concrete
600 g/m
2(1)
C (2)
100+
100++
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
(3)
3–12
6–25
9–35
50
C
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
2(1)
100+
NOTES:
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. See Appendix I, Paragraph I5.2.
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
Hardwood (Euc.Spp)
Durability Class 3 and 4
H5 to sapwood
12
Every 3 to 6
H5
20
Every 3 to 6
Softwood
Durability Class 4
NOTE: The inspection period will vary based on different species of timber and
field experience.
COPYRIGHT
COPYRIGHT
FIGURE D4 NOMINAL SERVICE LIFE FOR TIMBER POLES
NOTE: Criteria for Zone 2 applies to all parts of New Zealand.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
147
AS/NZS 7000:2016
AS/NZS 7000:2016
148
TABLE D4
SUGGESTED RANGE OF NOMINAL SERVICE LIFE
OF TIMBER POLES
Service life expectancy (years)
Zone (see
Figure D4)
H5 treated timber to AS 1604.1
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
NOTES:
1
A guide to the service life of various Australian timber pole species is given in the Timber
Service Life Design Guide published by Forestry and Wood Products Australia.
The class refers to the durability class.
Class 4 hardwood service life is assessed from Tasmanian hardwood poles.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
2
3
COPYRIGHT
149
AS/NZS 7000:2016
APPENDIX E
DESIGN FOR LIGHTNING PERFORMANCE
(Normative)
E1 GENERAL
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 1.5 and 2.5
ground strikes per sq km per year (30 and 50 thunderdays), and high level above 2.5 ground
strikes per sq km per year (50 thunderdays).
The acceptable outage rate due to lightning is therefore one of the most dominant design
parameters for an overhead line.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
E2 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
as follows:
(a)
Installation of earthwire.
(b)
Having wood in the flashover circuit (cross-arm or pole).
(c)
Critical flashovervoltage (CFO) of the insulators.
(d)
Pole footing resistance.
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 1 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:
Itotal = [Iwood2 + Iinsulator 2]1/2
. . . E1
where
Iwood
= impulse strength of wood
Iinsulator
= impulse strength of insulator
When an overhead earthwire is installed on wood pole lines, generally a down lead is run to
earth to provide a low resistance path to ground. A low pole footing resistance offers the
following advantages:
(i)
Reduces the probability of lightning induced backflashovers.
(ii)
Reduces risk of injury to persons or animals due to rises in earth potential at the
structure and the surrounding soil.
COPYRIGHT
AS/NZS 7000:2016
150
(iii) Provides a low impedance path for earth faults to ensure there is sufficient fault
current to operate protection relays.
E3 MEASURES TO IMPROVE LIGHTNING PERFORMANCE
A reduction in lightning outage time on transmission lines can be achieved by installing
autoreclosing schemes.
An improvement in lightning outage rates, particularly for distribution lines, can be
achieved by using wood in the cross-arms 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
This performance can be described by the shielding failure flashover rate, Rsf, and by the
backflashover rate, Rb. 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.
E4 REFERENCE
DARVENIZA, M. Electrical Properties of Wood and Line Design published by University
of Queensland, 1978.
COPYRIGHT
151
AS/NZS 7000:2016
APPENDIX F
TIMBER POLES
(Normative)
F1 GENERAL
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
This Appendix provides design properties and design methods for round timber utility
poles. The latest version of AS 1720.1 does not completely align with the provisions and
intent of this Standard for round timber utility poles as used in Australia, and its use has the
potential to impart undue cost implications to network owners. The 1997 version of
AS 1720.1 is more appropriate for timber pole design based on industry experience and
testing, when combined with the additional requirements of this Appendix. This Appendix
aligns primarily with the 1997 version. For New Zealand timber poles and processes
NZS 3603 is appropriate, and for all other sawn or manufactured poles the latest version of
AS 1720.1 is applicable.
F2 NOTATION
The following notation is used in this Appendix:
k1
= the duration of load factor
k12 = the stability factor for compression, determined in accordance with Paragraph F4.8
k20 = the immaturity factor
k21 = the shaving factor
k22 = the processing factor
kd
= 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
fs′ = the characteristic strength in shear
Ac
= the cross-sectional area at the critical section
=
As
3π d p2
16
= the section modulus
=
dp
4
= the shear plane area
=
Z
π d p2
π d p3
32
= the pole diameter at the critical section
COPYRIGHT
AS/NZS 7000:2016
152
ZT = torsional section modulus
=
π d p3
16
F3 CHARACTERISTIC STRENGTHS AND ELASTIC MODULI
The characteristic strengths and elastic moduli for 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 in-grade or proof testing.
Strength groups and joint group classifications shall be assigned to species in accordance
with AS 1720.2.
TABLE F1
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
POLE TIMBERS GRADED TO AS 2209—RELATIONSHIP BETWEEN
STRENGTH GROUPS AND CHARACTERISTIC PROPERTIES (MPa)
Strength
group
Stress
grade
Bending
( fb′ ) (1)
Tension parallel to
grain ( f t′) (1)
Hardwood
Softwood
Shear
( fs′)
Compression
parallel to grain
( fc′) (1)
Short duration
modulus of
elasticity (E) (2)
S1
F34
100
60
—
7.2
75
21 500
S2
F27
80
50
—
6.1
60
18 500
S3
F22
65
40
—
5.0
50
16 000
S4
F17
50
30
26
4.3
40
14 000
S5
F14
40
25
21
3.7
30
12 000
S6
F11
35
20
17
3.1
25
10 500
S7
F8
25
15
13
2.5
20
9100
NOTES:
1
The equivalence expressed in the table above is based on the assumption that softwood poles
(i.e. S5, S6 and S7) are cut from mature trees or stress graded as per the above strength groups.
2
The modulus of elasticity (E) is an average value and includes an allowance of about 5% for shear
deformation. For estimating a fifth percentile value, expressions are given in Paragraph F5.6.
TABLE F2
CHARACTERISTIC STRENGTH PROPERTIES (MPa)
FOR BEARING AND SHEAR AT JOINTS
Bearing
Strength
group
Shear at joint details
( fs′) (see Note)
Perpendicular to
grain ( fn′ ) (see Note)
Parallel to grain
( ft′) (see Note)
S1
S2
S3
—
—
—
60
50
40
7.2
6.1
5.0
S4
S5
S6
26
21
17
30
25
20
4.3
3.7
3.1
S7
13
15
2.5
NOTE: See Paragraph F5.
COPYRIGHT
153
AS/NZS 7000:2016
F4 DESIGN FACTORS—MATERIAL
F4.1 Capacity factor (strength reduction factor)
Values for the capacity factor ( φ), for calculating the design capacity of poles ( φR), 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 φ shall apply for calculating the design capacity
φ
All properties
0.90
( fb′ )
0.95
All other properties
0.90
( fb′ )
0.95
All other properties
0.90
Poles graded to AS 2209
Poles graded using proof testing in
accordance with Clause 8.5.2
Poles with bending properties established
from in grade evaluation and subject to
periodic testing/monitoring of properties
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
F4.2 Duration of load effects (strength)
The effect of duration of load on strength of timber poles and components is given by the
modification factor k1, as specified 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 Appendix G of AS 1720.1 (1997 or 2010 version).
F4.3 Duration of load effects (stiffness)
For timber poles subject to sustained bending, creep effects shall 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 j2 or j3, as given in AS 1720.1
or NZS 3603. The 1997 and 2010 Standards can be used interchangeably in this regard.
TABLE F4
DURATION OF LOAD FACTOR FOR STRENGTH
Effective
duration of
peak load
Modification factor (k 1)
for strength of poles
and timber components
(see Note)
Modification factor (k 1)
(see Note) for strength of
timber connections using
laterally loaded fasteners
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 sub-alpine areas)
3 days
0.94
0.77
3 months
0.80
0.69
>1 year
0.57
0.57
Type of load
Instantaneous
(e.g. ultimate wind and earthquake)
Long-term
(e.g. snow/ice in alpine areas)
Permanent
NOTE: See Paragraph F4.2.
COPYRIGHT
AS/NZS 7000:2016
154
F4.4 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. Pole degradation factors shall be determined from Table F5 unless other factors
can be determined by testing and statistical data.
The values of kd 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 systematic inspection and maintenance program is in place, the values of k d
given in Table F5 for untreated timbers should be chosen to reflect the strength assessment done
during the inspections (e.g. how much loss of strength is allowed at time of inspection before the
pole is replaced).
TABLE F5
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
POLE DEGRADATION FACTORS
Type of pole
(in accordance with AS 2209)
Pole diameter
d <250 mm
Pole diameter
250 ≤ d
≤ 400 mm
Pole diameter
d >400 mm
kd
kd
kd
20
1.0
1.0
1.0
50
0.80
0.85
0.90
20
1.0
1.0
1.0
50
0.80
0.85
0.90
20
0.80
0.90
1.0
50
0.50
0.55
0.60
20
0.70
0.80
0.90
50
0.30
0.40
0.45
Design life
(years)
Full length preservative-treated softwood
Full length preservative-treated hardwood
Durability Class 1 untreated hardwood
Durability Class 2 untreated hardwood
F4.5 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 k20 and j9 from Table F6,
for strength and stiffness respectively.
TABLE F6
IMMATURITY FACTORS k20 FOR DESIGN CAPACITY
AND IMMATURITY FACTORS j 9 FOR STIFFNESS
Immaturity factor k 20/j 9
Species
d = 100 mm d = 125 mm d = 150 mm d = 175 mm d = 200 mm d = 225 mm d = 250 mm
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
COPYRIGHT
155
AS/NZS 7000:2016
F4.6 Shaving factor
For timber members, the design characteristic strength properties shall be reduced if the
poles have been shaved, when modified from the natural pole form. The shaving factor for
strength k21 shall be determined as specified in Table F7. In addition to this modification for
strength, the values specified for stiffness (E) in Table F1 shall be reduced by 5% for
shaved poles.
TABLE F7
SHAVING FACTOR k21
Eucalypt and Corymbia Softwood species
k 21
species k 21
Characteristic property
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
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
F4.7 Processing factor
Where poles are steamed under pressure as a part of the manufacturing and fabrication
process, the characteristic strength properties shall be reduced using k22.
For poles that are steamed, k22 = 0.85, otherwise k22 = 1.0.
F4.8 Stability factor for compression
The stability factor k12 for modification of the characteristic strength in compression shall
be given by the following:
For ρcS ≤10—
k12 = 1.0
. . . F1
For 10 <ρcS ≤20—
k12 = 1.5 − 0.05ρcS
. . . F2
For ρcS ≥20—
k12 =
200
. . . F3
(ρ c S )2
where
S = 1.15
L
dp
S = slenderness coefficient
L = the distance between effective restraints in any plane
dp = the nominal mid-length diameter between the points of restraint
and where a conservative value of the material constant ρc is given in Table F8. More
accurate values of ρc may be derived in accordance with Appendix E of AS 1720.1—1997.
Note, however, that minimal testing has been conducted on full-scale poles in compression
and experience suggests that even with a more accurate material constant, the design of
timber utility poles in compression will be conservative.
COPYRIGHT
AS/NZS 7000:2016
156
TABLE F8
MATERIAL CONSTANT ρc FOR TIMBER
UTILITY POLES
Material constant ρc
Strength
group
Seasoned timber
Unseasoned timber
S1
S2
S3
1.25
1.22
1.20
1.43
1.39
1.37
S4
S5
S6
1.16
1.10
1.07
1.33
1.26
1.24
S7
1.04
1.20
F5 DESIGN CAPACITY
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
F5.1 Bending strength
The design capacity of poles in bending ( φM) for the strength limit state, shall satisfy the
following:
φM ≥ M*
. . . F4
φ M = φ k1 k20 k21 k22 kd ( f b′Z )
. . . F5
F5.2 Shear strength
The design capacity of poles in shear ( φV) for the strength limit state, shall satisfy the
following:
φV ≥ V*
. . . F6
φV = φ k1 k20 k22 kd ( f s′As )
. . . F7
F5.3 Compressive strength
The design capacity of poles in axial compression (φNc) for the strength limit state, shall
satisfy the following:
φNc ≥ N*
. . . F8
φ N c = φ k1 k12 k20 k21 k22 kd ( f c′Ac )
. . . F9
F5.4 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* ⎞
⎟ ≤1
⎜
⎟+⎜
⎝ φ M ⎠ ⎝ φ Nc ⎠
. . . F10
COPYRIGHT
157
AS/NZS 7000:2016
F5.5 Torsional strength
The design capacity of poles under torsion about the pole axis ( φT) for the strength limit
state shall satisfy the following equations:
φT ≥ T*
. . . F11
φT = φ k1 k20 k22 kd ( fs′Z T )
. . . F12
NOTE: The torsional rigidity of timber poles is normally very high, with the result that in most
situations the pole will rotate in the ground rather than 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.
F5.6 Pole top deflection
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 Table F1 are
average values for unseasoned timber.
For situations where pole deflection is critical, designers shall use fifth percentile values of
MOE. For poles, an approximation of the fifth percentile MOE is obtained by multiplying
the average MOE by 0.5.
It is recommended that poles subjected to sustained resultant loads be considered deflection
sensitive. For example, a service, streetlight fitting or deviation angle may result in the
structure developing a pronounced permanent bend as it undergoes in situ drying.
COPYRIGHT
AS/NZS 7000:2016
158
APPENDIX G
LATTICE STEEL TOWERS (SELF SUPPORTING AND GUYED MASTS)
(Informative)
G1 CALCULATION OF INTERNAL FORCES AND MOMENTS
G1.1 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, the designer should
consider all the likely configurations and select the member sizes to satisfy each of these
configurations.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
As many towers may have non-symmetrical leg combination it is important to consider
loading from all possible directions.
Primarily latticed towers are analysed as ideal elastic three dimensional trusses, pinned
connected at joints. Such elastic analyses produce only joint displacements tension, and
compression in tower members and tension in stays.
Moments from normal framing eccentricities are not calculated in the analysis. However,
bending moments in members because of framing eccentricities, eccentric loads or
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 non-linear) elastic analysis, structure
displacements under loads create member forces and these additional member forces are
called the PΔ 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 should 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 an 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 design for deflections or vibration of lattice towers.
G1.2 Guyed structures
Guys produce uplift loads on the guy foundation or anchor and compression loads on the
structure and its foundation. The guys should 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.
COPYRIGHT
159
AS/NZS 7000:2016
Externally guyed supports (i.e. guyed masts) utilizing multiple stay arrangements are
sensitive to inaccurate amounts of pretension in the guys.
The initial and final modulus-of-elasticity of the guys and creep of the guys together with
the flexibility of the tower should be used to compute the forces in tower members and
foundation reactions.
G2 EMBEDMENT OF STEEL MEMBERS INTO CONCRETE BY MEANS OF
ANCHORING ELEMENTS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The total tensile or compression load of steel leg members anchored in concrete is
transferred to the concrete by two methods as follows:
(a)
Steel angle stubs with anchoring elements such as angle cleats or studs These
should be checked for shear due to the compression stresses between the element and
the concrete. No bending moment in cleats or studs should be considered.
(b)
Base plate and holding-down bolts The holding-down bolts should be checked for
shear, axial load as well as possible bending moments due to lateral displacement of
the bolts.
G3 CRANKED K BRACING
For large tower widths, a bend may be introduced into the main diagonals (see Figure G1).
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.
FIGURE G1 CRANKED K BRACING
G4 PORTAL FRAMES
A horizontal member is sometimes introduced at the bend to turn a braced panel into a
portal frame (see Figure G2). 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.
COPYRIGHT
AS/NZS 7000:2016
160
FIGURE G2 PORTAL FRAME
G5 SECONDARY (REDUNDANT) MEMBERS
The following guidelines may be applied to the nominal bracing design (see Figure G3):
(a)
Face bracing:
(i)
All members inclined ≤10° are considered horizontal—
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Load =
(ii)
2.5%
2
= 1.77% of main member force.
Members inclined >10° and connected to the main leg—
Load =
2.5%
= 1.25% of main member force.
2
(iii) Members inclined >10° and not connected to the main
Force to balance vertical component of the connected inclined members.
(iv)
(b)
Members inclined ≤30° to be checked for bending with 1.4 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)
leg—
Members inclined >10°—
Load =
2.5%
2
= 1.77% of main member force.
COPYRIGHT
161
AS/NZS 7000:2016
1.0 % of th e m a i n l e g l o ad
ba l a n c i n g 1.25% f ro m th e
c o n n e c te d b r a c e
B ra c e l o ad
2.5% P/ 2 e ac h
Inclined brace
2.5% P/—2
H o r i zo nt a l b r a c e
2.5% P
R e s tr a i nt
2.5% P/—2
L EG EN D :
P = M a x i m u m m a i n m e m b e r c o m p re s s i o n fo rc e
B1
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Inclined braces
2.5% P/ 2
a1
B2
a2
Force balancing ver tical
component of member
connected to the main leg
B1= B2* sin ( a2) / sin ( a1)
H o r i zo nt a l b r a c e s
2.5% P/—2 e ac h
FIGURE G3 SECONDARY (REDUNDANT) MEMBERS
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
and bolt slip).
G6 SECURITY OF FASTENERS
G6.1 General application
All bolt nuts on lattice steel towers should be locked in their tightened position against
loosing by wind induced vibration by the use of suitable methods such as spring washers,
locking pins or thread deformation.
G6.2 Bolts in tension
Where bolts on major loaded connection points are in permanent tension, they should be
fitted with lock nuts.
G6.3 Deterrent to vandalism
All bolts within 3000 mm of the ground should be secured to prevent or significantly deter
their removal by vandalism.
G7 ANTI CLIMBING DEVICES
Unauthorized climbing of structures supporting energized overhead lines is a public safety
issue that requires a national uniform standard of approach.
Consideration should be given to anti climbing devices or measures to prevent or
significantly deter unauthorized climbing.
COPYRIGHT
AS/NZS 7000:2016
162
G8 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;
(c)
the lower face of all cross-arms; and
(d)
vertical intervals not exceeding 15.0 m in the tower body.
Reference may be made to CIGRE TB 196 for guidance on choice of an appropriate bracing
panel arrangement.
G9 STRENGTH FACTORS ( φ)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Strength factors ( φ) which takes into account variability of material and workmanship for
structural components used in lattice steel towers should be taken as 0.9 unless otherwise
provided in the reference standard being used.
COPYRIGHT
163
AS/NZS 7000:2016
APPENDIX H
ELECTRICAL DESIGN ASPECTS
(Informative)
H1 CORONA
H1.1 General
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Corona discharges usually occur during inclement weather (i.e. rain and 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 that can also cause corona.
Another related effect is spark discharges that may occur between discs of bridging strings
that are lightly loaded, mechanically. Spark discharges can generate radio interference,
television interference and audible noise.
H1.2 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.
H1.3 Radio interference voltage
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.
COPYRIGHT
AS/NZS 7000:2016
164
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 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 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.
Guidance on limits for electromagnetic interference from overhead lines can be found in
AS/NZS 2344.
H1.4 Audible noise
H1.4.1 General
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 raindrops, 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
H1.4.2 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.
H1.5 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.
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 and these
fields can induce charges on nearby metallic objects. Unless these charges are addressed by
proper earthing, they can cause an electric shock to members of the public. These shocks
can range from fingertip touch perceptible to hand grab annoyance. The thresholds for these
sensations are given in Table H1. The design limit is 5 mA.
COPYRIGHT
165
AS/NZS 7000:2016
TABLE H1
REACTION TO SPARK DISCHARGES
Threshold
Reaction/sensation
Energy
(milliJoules)
Charge
( μCoulombs)
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 current 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 SA 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 object.
(c)
Installing a shield wire on the overhead line.
(d)
Increase the separation between the circuit or object and the overhead line.
(e)
Limiting the fault current.
(f)
Improving the protection operating time.
COPYRIGHT
AS/NZS 7000:2016
166
APPENDIX I
CONCRETE POLES
(Informative)
I1 GENERAL
Concrete pole design and manufacture should comply with the requirements of
AS/NZS 4065, AS 3600 or NZS 3101.
The design strength of the concrete pole should be able to resist the axial force, bending
moments including any additional bending moments induced by slenderness effects. For
slender columns a moment magnification factor needs to be determined.
For typical distribution poles the design given in this Appendix may be used.
I2 STRENGTH
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
I2.1 Characteristic or specified compressive strength
The characteristic or specified compressive strength at 28 days should not be less than
40 MPa.
I2.2 Tensile strength
The characteristic flexural tensile strength of concrete can be determined statistically from
test in accordance with AS 1012.11. In the absence of more accurate data the lower
characteristic tensile strength (at 28 days and 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 c′ .
(b)
For pole elements subject to transient tensile stresses, 0.8 f c′ .
I2.3 Combined bending and compression strength
Where a pole is subjected to combined bending and compression load effects, the diameter
should be such that the following is satisfied:
⎛ M * ⎞ ⎛ N c* ⎞
⎟ ≤1
⎜
⎟+⎜
⎝ φ M ⎠ ⎝ φ Nc ⎠
. . . I1
I3 STRENGTH CAPACITY FACTOR
For poles designed by load testing in accordance with Clause 8.5, the strength capacity
factor ( φ) should not be taken as greater than 1.0.
For poles designed by calculation, φ should 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.
COPYRIGHT
167
AS/NZS 7000:2016
I4 SERVICEABILITY
I4.1 General
Concrete poles should meet the serviceability criteria, appropriate to the use of the pole, set
out in Paragraphs I4.2 and I4.3.
I4.2 Deflection and rotation
For electromotive transport poles, communication equipment poles, and some floodlighting
poles, deflection and rotation parameter should be determined by the operating system
constraints. For most other uses, deflection and rotation should not be considered a
serviceability constraint unless specified by the purchaser.
I4.3 Crack width
Crack widths at the serviceability limit state should not exceed values given in
Paragraph D3.7. For sustained dead loads or cable tension loads, the long-term effects of
creep and shrinkage should be considered.
NOTE: For further information on concrete crack width see Appendix D.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
I5 CONCRETE COVER
I5.1 Exposure classifications
The exposure classification for poles should 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 should 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 or 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)
Corrosion inhibitor in concrete mix.
(h)
Any other appropriate action.
COPYRIGHT
AS/NZS 7000:2016
168
I6 REINFORCEMENT AND TENDONS
I6.1 General
All reinforcement and tendons should be effectively maintained in their correct position
during manufacture of the pole. All supports used for this purpose should be made from
durable and stable materials that are not deleterious to the concrete or the reinforcement.
I6.2 Poles designed by load testing
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
(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.
I7 ELECTRICAL EARTHING
Provision should be made for bonding electrical equipment and external metalwork to steel
reinforcing and any earthing electrode.
COPYRIGHT
169
AS/NZS 7000:2016
APPENDIX J
COMPOSITE FIBRE POLES
(Informative)
J1 GENERAL
Poles made from composite materials should 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 should be suitable for the exposure and design service conditions
without jeopardizing operational security of the line.
Special attention should be given to use of fire resistant materials in rural/semi rural
applications.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 SERVICEABILITY LIMITS
Composite fibre poles typically exhibit large deflection limits and these limits need to be
considered in the design. Manufacturer test data will provide deflection limits at appropriate
loads for use in design of the pole. It is recommended that for serviceable loads, the
maximum deflection of the pole is 5% of pole height above ground.
COPYRIGHT
AS/NZS 7000:2016
170
APPENDIX K
STEEL POLES
(Informative)
K1 GENERAL
Steel pole structure design and manufacture should comply with the requirements of
AS 4100, NZS 3404.1, AS/NZS 4600, AS/NZS 4676, AS/NZS 4677 or ASCE 48-05 as
appropriate, and the provisions of Paragraphs K2 to K11.
K2 STRENGTH FACTORS ( φ)
Strength factors ( φ) which take into account variability of material and workmanship for
steel pole components used should be taken as 0.9 unless otherwise provided in the
reference standard being used.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Loading considered in design should include combined bending and axial loading of the
pole element.
K3 MINIMUM THICKNESS
The minimum plate thickness should not be less than allowed by the appropriate design
Standard.
K4 REQUIREMENTS FOR PLATE THICKNESS LESS THAN 3 mm
Where the thickness of steel plate used in a pole is less than 3 mm, the following
requirements apply:
(a)
Welding Special attention should be given to weld quality in thin-walled elements
and in particular to the avoidance of weld undercut.
(b)
Fatigue Structural detailing should 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 should 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 with the use of thick base plates that have been cut from thick steel
blooms. These 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.
COPYRIGHT
171
AS/NZS 7000:2016
K7 HYDROGEN EMBRITTLEMENT ISSUES WITH HOT DIP GALVANIZING
AFTER INCREMENTAL BENDING
Where incremental bending techniques or pressing is employed to form thick plates
(for poles) 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 should
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
K9 SLIP JOINTING
Where joints in segmented construction make use of overlapping close tolerance slip joints
they should be detailed such as to provide a minimum overlap of 1.5 times the largest
inscribed circle of the components being joined. The fabrication tolerances are to ensue that
the minimum constructed overlap of 1.35 times the largest inscribed circle of the
components being joined is attained.
Designs should 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 may be proportioned to comply with the
relevant Standard.
K11 ELECTRICAL EARTHING
Provision should be made for bonding electrical equipment and external metalwork to steel
reinforcing and any earthing electrode.
COPYRIGHT
AS/NZS 7000:2016
172
APPENDIX L
STRUCTURE FOOTING DESIGN AND GUIDELINES FOR THE
GEOTECHNICAL PARAMETERS OF SOILS AND ROCKS
(Informative)
L1 GENERAL PRINCIPLES
This Appendix 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.
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
For simple direct embedded pole footings some design methods allow for a ‘serviceability’
design criteria based on allowing for the deformation of the soils under loads less than the
ultimate design loads. See SA HB 331 for further guidance on alternative approaches that
can be adopted.
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.
L2 GEOTECHNICAL PARAMETERS OF SOILS AND ROCKS
L2.1 General
Geotechnical investigation should be carried out along the easement of a 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. Calculate this as follows:
s = c + σn tan ϕ
. . . L1
where
s = shear strength
c = cohesion
σn = normal stress
ϕ = angle of internal friction
COPYRIGHT
173
AS/NZS 7000:2016
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-term and long-term conditions and this
standard recommends that for ‘granular’ soils the same properties are to be used under both
long-term and short-term loads. Dense saturated granular materials typically show a
reduction in internal friction of 1° to 2° from the dense dry values.
L2.2 Typical soil properties
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Geotechnical parameters for soil strata may be taken from Tables L1, L2, and L3. The
values for rock 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
Unit weight
Shear strength, C u
(kPa)
(kN/m 3 )
Undrained
Very soft
16–19
0 to 10
Exudes between fingers
when squeezed in hand
Soft
17–20
10 to 25
Can be moulded by light
finger pressure
Firm
17.5–21
25 to 50
Can be moulded by
strong finger pressure
Stiff
18–22
50 to 100
Cannot be moulded by
fingers. Can be indented
by thumb
Very stiff
21–22
100 to 200
Hard
20–23
≥ 200
Term
COPYRIGHT
Field guide to
consistency
Can be indented by
thumb nail
Can be indented with
difficulty by thumb nail
AS/NZS 7000:2016
174
TABLE L2
TYPICAL PROPERTIES OF NON-COHESIVE SOILS
Angle of friction, ϕ
Unit weight
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Soil type
3
(kN/m )
(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
20°–22°
Medium dense, fine and silty sand
17–19
25º–30º
Dense to very dense, fine and silty sand
19–21
35º–40º
TABLE L3
TYPICAL PROPERTIES OF ROCK
Ultimate design values
Shear (kPa)
Bearing (kPa)
Unit weight
(kg/m 3 )
1200
6000
27
1000
2500
24
750
1500
24
Type/classification
Hard
Igneous
Basalt
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
(continued)
COPYRIGHT
175
AS/NZS 7000:2016
TABLE L3 (continued)
Ultimate design values
Type/classification
Shear (kPa)
Bearing (kPa)
Unit weight
(kg/m 3 )
Soft rock
Soft sandstone
Mudstone
275
450
22
Medium shale
Phyllite
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
Geotechnical investigation should also report on the appropriate values of a horizontal soil
stress required to establish the ultimate capacity of the footing. In addition, Table L4
provides a basic guide for horizontal soil stress evaluation.
TABLE L4
HORIZONTAL SOIL STRESS
Soil and backfill condition
Native soil with loose
backfill
Native soil with moderately
compacted backfill
Native soil with back
compacted backfill
Backfill, lightly compacted
Backfill, moderately
compacted
Backfill, well compacted
K—Drained condition
K—Undrained condition
K = Ka
K = Ka
K = 0.5 to 1.0 (min K = K a )
or K 0 for in situ
K = 0.5 to 1.0 (min K = K a )
or K 0 for in situ
K ≥ 1 or K 0 for in situ
K ≥ 1 or K 0 for in situ
K = K0
K = 0 to K a
K = 2/3 to 1.0
K = K a to K 0
K > = 1.0
K = K 0 to 1.0
Native soil
(un-cemented sands)
K = K a for D S ≤300 mm
Native soil
(un-cemented sands)
K = 0.5(K a + K0 ) for 300 < D S ≤ 600 mm
Native soil
(un-cemented sands)
K = 0.333(K a + K 0 + K p ) for DS >600 mm
LEGEND:
K 0 = 1 − sin ϕ
K a = tan 2 (45 − ϕ /2)
K p = tan 2 (45 + ϕ /2)
COPYRIGHT
AS/NZS 7000:2016
176
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 Appendix concentrates on the design requirements for lateral loads and moments only.
When there are special requirements for compression loading the footings should be
checked using established principles.
L3.2 Bored piers
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The Brinch Hansen method presented here is considered to be appropriate to the
dimensional range and characteristics of poles in transmission line structures. Alternative
methods are given in SA HB 331.
The Brinch Hansen method does not provide an indication of pole rotation at the nominal
failure load. However, ground line rotation when using Brinch Hansen is typically 2° for
undrained conditions. For drained conditions the equation predicts overturning moments
typically corresponding to 5° rotation.
Failure of the footing, that is when the rotation increases markedly for little increase in
load, is typically associated with rotations of 5°. Accordingly, the calculated footing
capacity in drained conditions should be appropriately factored down.
L3.3 Analytical procedure for determination of failure load/moment
L3.3.1 Brinch Hansen method
The mathematical model of the pole/soil system is shown in Figure L1.
M
Ground sur face
H
Rigid body
r ot a t i o n
Zr
F1
Z2
Backfill
L
Z1
Z
Pz
C e nt r e
of r ot ati o n
F2
D
S o i l p r e s s u r e d i s t r i b u ti o n P z
FIGURE L1 MODEL OF THE POLE/SOIL SYSTEM
The system is subjected to a ground line lateral load, H*, and bending moment, M*.
H* ≤ φg × H
M* ≤ φg × M
φg
= geotechnical capacity reduction factor varies from 0.8 to 0.5
H, M = corresponding ground line lateral load and bending moment capacity
COPYRIGHT
177
AS/NZS 7000:2016
The ‘effective diameter’, D, can be taken as the average pole diameter below ground for
soil backfill situations and the auger diameters 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, zr, below the surface. At the point of failure, this rotation
produces a soil stress distribution as depicted in Figure L1 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—
Pz = qzKq + cuKc
. . . L2
where
qz
= vertical overburden pressure at depth z = γz
γ
= soil unit weight (see Tables L1 to L3)
cu
= soil shear strength (see Table L1)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Kq, Kc = factors that are a function of z/D and the soil angle of friction, φ
(see Table L2)
Values of Kq are given in Table L5, and those of Kc are given in Table L6.
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, zr. In general form the equations
are:
(a)
Horizontal equilibrium
H = F1 − F2
. . . L3
where
F1 =
F2 =
(b)
∫
zr
∫
L
0
zr
pz Ddz
. . . L4
pz Ddz
Moment equilibrium
M = F2z2 − F1z1
. . . L5
where
z1
= distance to resultant load F1
z2
= distance to resultant load F2
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,
zr, 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 F1 and F2 may be based on the Brinch
Hansen method. The forces should be based on soil pressure pz and the areas of the bed log
and the pole foundation.
COPYRIGHT
AS/NZS 7000:2016
178
TABLE L5
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
EARTH PRESSURE COEFFICIENT FOR OVERBURDEN PRESSURE, Kq
ANGLE OF FRICTION ϕ
z/D
0°
5°
10°
15°
20°
25°
30°
35°
40°
45°
1.0
0
0.50
1.10
1.85
2.81
4.12
5.99
8.85
13.50
21.81
1.5
0
0.52
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
2.65
4.25
6.60
10.27
16.20
25.98
42.55
8.0
0
0.64
1.53
2.71
4.37
6.82
10.69
17.05
27.63
45.59
9.0
0
0.65
1.56
2.77
4.47
7.02
11.07
17.82
29.18
48.54
10.0
0
0.66
1.58
2.82
4.56
7.19
11.41
18.53
30.64
51.39
12.0
0
0.68
1.62
2.89
4.71
7.47
12.00
19.79
33.34
56.81
14.0
0
0.69
1.65
2.96
4.82
7.70
12.49
20.88
35.77
61.90
16.0
0
0.70
1.68
3.01
4.92
7.89
12.90
21.82
37.96
66.69
18.0
0
0.71
1.70
3.05
5.00
8.05
13.25
22.65
39.95
71.20
20.0
0
0.72
1.72
3.08
5.07
8.19
13.55
23.38
41.77
75.46
COPYRIGHT
179
AS/NZS 7000:2016
TABLE L6
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
EARTH PRESSURE COEFFICIENT FOR COHESION, KC
ANGLE OF FRICTION ϕ
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 equations below.
NOTE: For more information on these formulas refer to the original Brinch Hansen paper
(see reference at the end of this Appendix).
K0 = 1 − sin ϕ
. . . L6
dc = 1.58 + 4.09 tan4ϕ
. . . L7
⎡
1 ⎞ ⎤
⎛1
N c = ⎢ eπ tan ϕ tan 2 ⎜ π + ϕ ⎟ −1⎥ cot ϕ
2 ⎠ ⎦
⎝4
⎣
. . . L8
⎛1
⎞
⎜ π + ϕ ⎟ tan ϕ
⎠
K q0 = e⎝ 2
⎛1
⎞
1 ⎞ −⎜ π −ϕ ⎟ tan ϕ
1 ⎞
⎛1
⎛1
cos ϕ tan ⎜ π + ϕ ⎟ − e ⎝ 2 ⎠ cos ϕ tan ⎜ π − ϕ ⎟
2 ⎠
2 ⎠
⎝4
⎝4
K q = N c d c K o tan ϕ
αq =
z
q
K =
(K
K q0
q
−K
0
q
)
1+ α q
. . . L10
K o sin ϕ
1 ⎞
⎛1
sin ⎜ π + ϕ ⎟
2 ⎠
⎝4
K q0 + K q α q
z
D
. . . L9
. . . L11
z
D
. . . L12
COPYRIGHT
AS/NZS 7000:2016
180
⎡ ⎛⎜ 1 π +φ ⎞⎟ tan φ
⎛π 1 ⎞ ⎤
K c0 = ⎢ e⎝ 2 ⎠ cos φ tan ⎜ + φ ⎟ − 1⎥ cot φ
⎝ 4 2 ⎠ ⎦⎥
⎣⎢
. . . L13
Kc = Ncdc
. . . L14
K c0
1 ⎞
⎛1
2 sin ⎜ π + ϕ ⎟
0
( Kc − Kc )
2 ⎠
⎝4
αc =
K cz =
K c0 + K c α c
1+ α c
z
D
. . . L15
z
D
. . . L16
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
where
z
= depth (metres)
D
= pile diameter (metres)
ϕ
= soil friction angle (radians)
Nc = bearing capacity factor
dc
= pressure at infinite depth factor
L3.3.2 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 assumed to be developed
as indicated in Figure L2.
d
Pile
Soil pressure
Compression strut
FIGURE L2 THEORETICAL SOIL PRESSURE DIAGRAM
The maximum shear value to be used in design calculations is as indicated in Figure L3.
COPYRIGHT
181
ZR
AS/NZS 7000:2016
Shear design values
L
d/2
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
d/2
FIGURE L3 EQUIVALENT PILE SHEAR DIAGRAM
L3.3.3 Design of shear reinforcement
Basic requirements for calculation should be based on provisions of AS 3600, and as
illustrated in Figure L4 and as set out below.
A bd
do
d
C
FIGURE L4 CALCULATION OF SHEAR REINFORCEMENT
V* ≤ φVu = φ (Vuc + Vus)
. . . L17
Concrete and longitudinal reinforcement contribution—
1
⎛ A f ′⎞3
Vuc = β1 β 2 β3 Abd ⎜ st c ⎟
⎝ Abd ⎠
. . . L18
COPYRIGHT
AS/NZS 7000:2016
182
where
β1 as per AS 3600
β2 as per AS 3600
β3 = 1.0
Ast = half of the longitudinal reinforcement area or area of longitudinal
reinforcement in tension
Abd = concrete area equivalent to AS 3600 ‘bvdo’ to be calculated as follows:
2
d2
⎛d
⎞
Abd = ( Π − α ) + ⎜ − c ⎟ tan (α ) (α in radians )
4
⎝2
⎠
. . . L19
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
where
α
−1 ⎛ d − 2c ⎞
= cos ⎜
⎟
⎝ d ⎠
do
= d−c
c
= the distance between the edge of the column and centre of the nearest
longitudinal bar
bv
= Abd/do
Remaining symbols are as per AS 3600
Shear reinforcement contribution—
⎛Π⎞⎛ A f d ⎞
Vus = ⎜ ⎟ ⎜ sv sv.f o ⎟ cot θ
s
⎝ 4⎠⎝
⎠
. . . L20
The minimum shear reinforcement should be provided as per AS 3600 and the shear
strength of a column with minimum reinforcement is given by the following:
⎛Π⎞
Vu.min =Vuc + ⎜ ⎟ 0.6 Abd
⎝4⎠
. . . L21
L4 FOUNDATION DESIGN FOR LATTICE STEEL TOWERS
L4.1 General
Some of the more commonly used foundation capacity calculation methods are presented in
the following text. A wide range of opinions and practices with respect to the analysis and
design of lattice tower foundations exist in Australia and around the World. Therefore the
presented methods should be applied with appropriate caution.
Reference should be made to IEEE 691, Canadian Foundation Engineering Manual and
specialized technical literature for more details.
Lattice tower footings are typically designed for vertical forces (uplift or compression)
combined with horizontal shear forces. The affect of footing movements due to differential
settlement and variation in soil types, should be considered in the design.
L4.2 Foundation types
There are many footing types used for transmission line lattice tower structures. This
Appendix outlines the design principles for the more common types only, as follows:
(a)
Bored straight-sided piers in soils (with or without undercut).
(b)
Bored piers socketed in soft to medium strength rock.
COPYRIGHT
183
(c)
Excavated footings.
(d)
Rock anchors.
AS/NZS 7000:2016
See Figure L5 for typical details.
G r o u n d l eve l
G r o u n d l eve l
Var i a b l e
d e pt h to
ro c k
C o lu m n
reinforc ing
Ro c k leve l
G r o u n d l eve l
C o lu m n
reinforc ing
to tr an sfer
l o ad
Shear
c o nne c tor s
C o lu m n
reinforc ing
S h o r t s tu b
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Ro c k
s o c ket
Le g stu b
an c h orag e
ALTERNATIVE
A
LTER N ATIVE CO
C O LU M N
ARR AN GEM ENT
B ORED SO CKE TED PIER
BORED
U N DERRE A M
UNDERRE
MED
ED PIER
Le g stu b
an c h orag e
C o n s tr u c t i o n
ex te n s i o n
G r o u n d l eve l
G r o u n d l eve l
C o m p ac te d
bac k fill
C o m p ac te d
bac k fill
Reinforc e d
c o n c rete c o lu m n
Var i a b l e
d e pt h to
ro c k
Ro c k leve l
C o lu m n
reinforc ing
Le g stu b
an c h orag e
Le g stu b
an c h orag e
C e m e nt o r
c h e m i c al
g r o u te d
te n d o n s
Base slab
BURIED SL
S L AB T YPE
RO CK AN CH
CHOR
OR T YPE
T YPICAL CLE AT AN CH OR AGE
FIGURE L5 TYPICAL TOWER FOOTING ARRANGEMENTS
COPYRIGHT
AS/NZS 7000:2016
184
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
L4.3 Common symbols
AB
= pier top bell area (excluding shaft)
ABU
= pier base area
AS
= pier side shaft area (excluding bell)
CC
= compression capacity
cu
= undrained soil shear strength
fs
= shaft adhesion = α cu (for α see Figure L7)
GC
= concrete weight
GR
= rock weight
GS
= soil weight
K
= coefficient of horizontal soil stress should be evaluated for drained or undrained
conditions as appropriate (see Table L4 for guidance)
Nq
= bearing capacity factor = e πtan ϕ tan2 (45 + ϕ/2)
QB
= bearing on top of bell (where applicable)
QBU = bearing at base of pier bell
QR
= rock pier side resistance
QS
= soil side resistance along soil-concrete interface
QSS
= side resistance along soil-to-soil interface
UC
= uplift capacity
ϕ
= soil internal friction angle (degrees)
δ
= Concrete-to-soil friction angle
φc
= concrete weight capacity reduction factor typically 0.9
φg
= geotechnical capacity reduction factor varies from 0.8 to 0.5
φs
= soil weight capacity reduction factor typically 0.8
γs
= effective unit weight of soil
δs
= soil-to-soil friction angle
L4.4 Footing design
L4.4.1 Bored piers
Bored piers are formed by augering a hole into soil (or soft rock), installing a 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 soil conditions provides enhanced uplift capacity. Belled piers are not
suitable for use in 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 the use of a
permanent liner/steel casing for at least part of the depth of the pier being installed.
Installation of the permanent liner will reduce the pier side resistance over the length of the
liner and this should be accounted for in the capacity analysis.
COPYRIGHT
185
AS/NZS 7000:2016
L4.4.2 Uplift analysis for piers in soil
L4.4.2.1 General
The failure mechanism depends significantly on the ratio of soil strength to soil stiffness.
Since reliable data on soil strength parameters 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 UC. Toe suction should not be used in uplift analysis.
L4.4.2.2 Undercut pier uplift capacity by shear failure model
The uplift capacity is calculated by assuming failure of shaft friction along the depth of the
shaft plus the bearing on the effective area of the undercut. (See Figure L6.)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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. The theoretical bearing capacity on the bell is only
achieved with substantial deformation of the soil. Such deformation may be sufficient to
cause secondary effects in the supported structure.
UC
QS
QS
L1
L
QB
Gc
QB
DS
DB
FIGURE L6 UNDERCUT SHEAR FAILURE MODEL
U C = φc G C + φg Q S + φg Q B
. . . L22
For an undrained condition side resistance is based on adhesion—
Qs = fsAS
. . . L23
And for a drained condition side resistance is based on friction—
Qs = 0.5γs × L1 × K × tan δ × AS
. . . L24
COPYRIGHT
AS/NZS 7000:2016
186
1.2
Reduction factor,
1
0.8
0.6
0.4
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
0.2
0
0
20
40
60
80
100
120
140
160
180
200
220
Undrained shear strength c u (kPa)
FIGURE L7 SHAFT ADHESION FACTOR
For undrained condition—
QB = AB (9cu + σV)
. . . L25
For undrained condition under sustained load—
QB = 0.5AB (9cu + σV)
. . . L26
For drained condition—
QB = AB σV Nq
. . . L27
where
σV = effective vertical stress = γSL1 for uniform soil profile
The bearing capacity component should be carefully evaluated and could be limited by a
weaker layer above the load bearing stratum.
L4.4.2.3 Undercut pier uplift capacity by equivalent cylinder failure model
This model of failure is based on failure of cohesion on the surface of an equivalent
cylinder which diameter equals the effective diameter of the undercut DE. (See Figure L8.)
The method uses soil cohesion, i.e. soil-to-soil friction that is calculated using cu in clays
and ϕ in sands.
U C = φc G c + φg Q C + φs G s
. . . L28
where
QC = side resistance of cylinder of effective pier diameter
COPYRIGHT
187
AS/NZS 7000:2016
QC = fcπDEL
. . . L29
where
fc
= soil cohesion, i.e. soil-to-soil friction that is equal to cu in clays and
γs tan δs × K × L1/2 in sands
DE = effective pier diameter = DS + (DB − DS)/ζ
ζ
= bell diameter reduction coefficient varies from 1.5 to 3
UC
DE
GS
GS
L1
L
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
QC
QC
Gc
DS
DB
FIGURE L8 CYLINDRICAL FAILURE MODEL
L4.4.2.4 Undercut pier uplift capacity by the earth cone pullout model
The earth cone pullout assumes that the uplift resistance is given only by the weight of soil
and footing within the cone (see Figure L9). 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. A cone angle of 30° has traditionally been used for
stiff cohesive soil.
The cone method only requires that the bore stands vertically and can be successfully
undercut at the time of construction. In addition, this method generally tends to
underestimate the uplift capacity for shallow piers with soil of medium to dense consistency
and stress states corresponding to normally consolidated or lightly over consolidated. For
deeper piers, the computed uplift resistance capacity increases rapidly with depth while the
test results indicate lower uplift capacities are likely to be achieved. 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.
COPYRIGHT
AS/NZS 7000:2016
188
UC
GS
GS
Gc
S
FIGURE L9 UNDERCUT CONE FAILURE MODEL
Q U = φc G C + φs G S
. . . L30
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
where pullout angle
θS = varies between 20° to 30°
L4.4.2.5 Straight-sided pier uplift capacity by shear failure model
The uplift capacity is calculated by assuming failure of shaft friction along the depth of
shaft. (See Figure L10.)
UC
QS
QS
L
Gc
DS
FIGURE L10 STRAIGHT-SIDED SHEAR FAILURE MODEL
U C = φc G C + φg Q S
. . . L31
L4.4.2.6 Straight-sided pier uplift capacity by the earth cone pullout model
The earth cone pullout assumes that the uplift resistance is given only by the weight of soil
and footing within the cone. (See Figure L11.)
COPYRIGHT
189
AS/NZS 7000:2016
UC
GS
GS
S
Gc
FIGURE L11 STRAIGHT-SIDED CONE FAILURE MODEL
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
L4.4.3 Pier 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. (See Figure L12.)
The long-term drained compression capacity of piers in clay will be considerably larger
than the undrained capacity. Piers loaded in compression do not reach a clearly defined
ultimate capacity. Various load tests show that the pier capacity continues to increase
indefinitely as the 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. The maximum loads acting on transmission line footings
are from wind induced loads. However, it is a rare event when a transmission line footing
will settle the predicted amount due to the transient nature of the applied load.
CC
DS
QS
QS
L1
L
Gc
Q BU
DB
FIGURE L12 COMPRESSION ANALYSIS MODEL
COPYRIGHT
AS/NZS 7000:2016
190
CC = −φccGC + φgQS + φgQBU
. . . L32
where
φcc = capacity reduction factor typically 1.1
QS = fs AS
. . . L33
For undrained condition (cohesive soils)—
QBU = ABU (9cu + σV)
. . . L34
For drained condition (non-cohesive soils)—
QBU = ABU qult
. . . L35
where
qult = ultimate bearing capacity at pier base
The bearing capacity component should be carefully evaluated and could be limited by a
weaker layer below the load bearing stratum.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
L4.4.4 Bored piers socketed into rock
L4.4.4.1 General
In fractured rock, the failure mechanism can be complex and is dependent on the 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 needs to move (i.e. fail in rock) before adhesion-friction is realized
(conservative assumptions).
It is important to check stability of the rock mass particularly for relatively shallow
foundations. An ‘inverted cone’ of rock resists the socketed bored pier loads at failure, and
assumed fracture angles are a function of the hardness and structure of the rock mass
extending over the length of the rock socket.
Two uplift case failure modes (pier and cone pullouts) should be considered for piers
socketed into rock, and the critical case should be that giving the lowest capacity.
L4.4.4.2 Pier uplift capacity by mobilization of rock mass
The general ultimate pier pullout capacity is similar to the straight-sided bored pier and is
given as (see Figure L13).
U C = θc G c + φs G S + φR G R
. . . L36
where
θR = cone angle in rock
= 30° for soft, heavily weathered rock mass (similar to soil)
= 35° to 40° for intermediate rock quality and/or weathered
= 45° for continuous good quality rock without fracturing
φS = cone angle in soil varies between 20° to 30°
COPYRIGHT
191
AS/NZS 7000:2016
UC
GS
GS
S o il
S
Gc
GR
GR
Rock
R
FIGURE L13 ROCK/SOIL CONE MODEL
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
L4.4.4.3 Pier uplift capacity by shear failure model
The general ultimate pier uplift capacity by shear model (see Figure L14) is similar to the
straight-sided bored pier in soils and is calculated by assuming failure of shaft friction
along the depth of shaft.
UC
S o il
QS
QS
Gc
QR
LS
Rock
QR
LR
FIGURE L14 ROCK/SOIL SHEAR MODEL
U C = φc G c + φg + Q S + φg Q R
. . . L37
For an undrained condition side resistance is based on adhesion—
Qs = fsASS
. . . L38
And for a drained condition side resistance is based on friction—
Qs = 0.5γs × Ls × K × tan δ × ASS
. . . L39
Rock resistance—
. . . L40
QR = fRCASR
where
ASS = area of shaft in soil
ASR = area of shaft in rock
fRC = rock-concrete interface shear strength generally in range 300 kPa to 1500 kPa
COPYRIGHT
AS/NZS 7000:2016
192
L4.4.4.4 Pier compression analysis
The failure model for compression loading (see Figure L15) involves a bearing failure in
the rock below the toe of the pier. Typically piers in rock exhibit very minor downward
movement in relation to the surrounding soil.
CC
S o il
QS
QS
GC
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
QR
LS
Rock
QR
LR
QB
FIGURE L15 ROCK/SOIL COMPRESSION MODEL
CC = −φccGC + φgQS + φgQB
. . . L41
The bearing capacity component should be carefully evaluated and could be limited by a
weaker layer below the load bearing stratum.
L4.5 Spread footings
L4.5.1 General
Spread footings consist of a concrete shaft and an enlarged base of either mass concrete or a
pad (slab) of reinforced concrete.
Spread footings are formed by excavating square, rectangular or circular holes in soil or
rock using machines or hand-operated tools. The base of spread footings may be straight
sided, or may be undercut depending on soil conditions and the construction methods
adopted. In unstable soils over excavation (excessive batter) will be present stipulating the
failure mode through compacted fill and not in in situ materials.
Excavated footings are backfilled with the excavated soil, excavated soils improved by
cement or lime stabilization, or imported backfill materials when the excavated material
cannot be compacted to achieve the required uniform strength and/or density assumed in
design.
The design methodology 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 in situ materials. The
design process should check all possible modes of failure. The strength of the spread
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.
There are substantial differences between the uplift capacity of undercut and non undercut
footings. Tests indicate that footings with undercut pads will develop higher uplift
resistance than that of an equivalent footing without an undercut. Footings with undercuts
also have less displacement up to the point of pullout.
COPYRIGHT
193
AS/NZS 7000:2016
The bearing capacity component should be carefully evaluated and could be limited by a
weaker layer below the load bearing stratum.
It has been prudent in the past to limit the depth to width ratio of the excavation to 1.5 to 2
to facilitate construction.
L4.5.2 The earth cone pullout model with no undercut
UC
GS
GS
S
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Gc
FIGURE L16 CONE PULLOUT MODEL (NO UNDERCUT)
Uplift capacity:
Q U = φs G S + φc G C
. . . L42
The cone pullout capacity is based on varying cone angle θS = 20° to 30° measured from the
top of the footing base. (See Figure L16.)
L4.5.3 The earth cone pullout model with undercut
UC
GS
GS
Gc
S
FIGURE L17 CONE PULLOUT MODEL WITH UNDERCUT
Uplift capacity:
Q U = φs G S + φc G C
. . . L43
COPYRIGHT
AS/NZS 7000:2016
194
The cone pullout capacity is based on varying cone angle θS = 30° to 45° measured from the
toe of the footing base. (See Figure L17.)
θS = 30° for very stiff cohesive soils and soft, heavily weathered rock mass
(similar to soil)
= 35° to 45° for the proportion in rock that is at least low in strength or not
highly jointed vertically
L4.5.4 The pier pullout by cylinder failure model
Caution is required when assessing the capacity of non undercut footings as the soil
properties should be taken as the lesser of the insitu undisturbed ground and the installed
backfill. The cylinder failure line is to be considered from the toe of an undercut footing
and Qs = 0. Over excavation (battering back or stepping back) will also affect the estimation
of soil parameters for an undercut footing. (See Figure L18.)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
UC
Q SS
GS
GS
Q SS
LG
Gc
QS
QS
LS
BD
BW
FIGURE L18 PIER PULLOUT MODEL
UC = φcGc + φsGS + φs (Q S + QSS)
. . . L44
Unit resistance
Resistance
component
Drained condition
Undrained
condition
QSS
0.5LG γs K tan δs
As for drained
condition
2LG(BW + BD )
QS
(LG + 0.5LS)γs K tan δ
αcu
2LS(BW + BD )
Area
Grillage footings are also a type of spread footings, which were used extensively in the
past. Their use is now restricted to sites where access is difficult and/or the use of concrete
is not an option. Typically a grillage footing consists of steel members forming the pyramid
which is fixed to the tower stub. Backfill requirements are essentially the same as for
concrete spread footings.
COPYRIGHT
195
AS/NZS 7000:2016
Grillage foundations are more susceptible to bearing failure because of the high bearing
stresses generated by the relatively small surface area of the steel in contact with the soil. In
addition, for the grillage foundation in uplift, a wedge of soil in the form of a truncated,
inverted pyramid forms and the uplift loads are resisted by the weight of the soil and
grillage with soil shear capacity along the failure surface taken as zero. Cone failures are
possible because the spread footings are usually shallow and the horizontal soil stresses
(such as might be found in over consolidated soils) are relatively high.
L4.6 Rock or soil anchored footings
L4.6.1 General
This type of footing is based on the design principle that the applied loads (compression
and tension) are being transferred to the soil or foundation material by a number of soil or
rock anchors via a load transfer cap.
The progressive de-bonding of the anchor system employed with increasing load due to
elastic extension of the tension tendon should be considered.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
Ground anchors are active anchors, i.e. they are post-tensioned after installation, and locked
off with an initial load to keep anchor extensions at the design load compatible with pile
cap displacements. 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.
L4.6.2 Deep piled footings
Deep piled foundations are used where weaker soil strata is encountered. Deep pile types
are broadly classified into ‘displacement’ and ‘non-displacement’ piles. These may take a
variety of forms and can be based on concrete cast in situ piles, steel driven or screw piles
or precast concrete driven pile systems.
The piled footing should be designed for the following characteristics:
(a)
Ultimate strength.
(b)
Serviceability.
(c)
Durability.
Piling design and installation should comply with the requirements of AS 2159.
The installation of any pile system should confirm deign assumption. In addition, the screw
piling system requires a good knowledge of the soil properties, and the screw pile ultimate
capacity can only be confirmed if both the installation torque and the pile depth are
achieved.
The design of the screw piles shafts should be based on Eurocode 4.
L4.6.3 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 shallow
depth raft slab footings above or partially below ground may provide an acceptable 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 resist vertical uplift loads.
COPYRIGHT
AS/NZS 7000:2016
196
The stability of the footing and structure is provided by the composite action of the mass of
the completed raft.
L4.6.4 Load transfer from tower leg to footings
L4.6.4.1 General
Connections between tower leg stubs and concrete footings may be by means of a base plate
and anchor bolts extending into the concrete of the footing, or by extending the stub into the
concrete shaft and providing suitable means to transfer the stub forces to the concrete.
L4.6.4.2 Design of base plates
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Base plate design should generally be 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 the base plate is the net friction dependent on the degree of
prestress in anchor bolts. Concrete column shafts should be proportioned to resist axial,
moment and shears forces from the tower and any localised effects from anchor bolts,
e.g. bursting.
Bending of base plates may be checked using yield line methods of analysis. If all possible
yield lines patterns have been investigated, the lowest computed value for the ultimate
moment (assuming plastic section properties) is the ultimate capacity.
L4.6.4.3 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 that transfer force, in a bearing mode to
the concrete. In stubs that do not extend to the base of the footings, lapping reinforcement
in the shaft transfers the stub forces to the base of the footing.
The bond between the stub and the surrounding concrete is adversely affected by the shape
and finish on galvanized 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 in tension the
assumed friction bond should be limited to 0.35 MPa if the stress in the stub is less than
300 MPa, or ignored in the design calculations if the stress is greater than 300 MPa.
Assumed friction bond in compression should not exceed 0.7 MPa.
Most of the stub axial force is resisted by shear connections. The normal method is to
provide bolted or welded cleats or studs attached 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 yield 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 not to 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 cleat flange 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 limited, such as in reinforced concrete shafts.
COPYRIGHT
197
AS/NZS 7000:2016
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 force 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 required bond strength in the
reinforcement.
L5 GUYED ANCHORS
L5.1 Cast in situ anchor blocks
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Anchors for guys can be installed by boring or excavating a vertical shaft into which feeds
an inclined anchor tendon or stay rod (see Figure L19). 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.
UC
SC
Ground line
GS
LG
S1
S2
GC S2
S2
S3
LA
S2
PP
PA
S3
BD
BW
FIGURE L19 CAST IN SITU ANCHOR BLOCK
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 a backfill
material. Even at sites where cohesive soils are present it is preferable to backfill with
granular material.
Anchor resistance is checked separately for vertical and horizontal component of the stay
tension.
COPYRIGHT
AS/NZS 7000:2016
198
Uplift resistance is—
U C = φs G S + φc G C + φg S 2
. . . L45
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
where
S1
= shearing resistance on base block
S2
= shearing resistance on perimeter of anchor
Unit resistance
Resistance
component
Drained condition
Undrained
condition
Area
S1
LGγs K tan δ
αcu
BW × BD
S2
(LG + 0.5LA)γs K tan δ
αcu
2LA(BW + BD )
α
= capacity reduction factor (see Figure L7)
K
= refer Table L4
γs
= effective unit weight of soil
Sliding resistance is—
SC = φg(PP – PA +S1 +S3)
. . . L46
where
SC = horizontal sliding resistance
PA = active pressure on the back of anchor
PP = passive pressure on the front of anchor
S1
= shearing resistance at the top of anchor
S3
= shearing resistance on the sides of anchor
Unit resistance
Resistance
component
Drained condition
Undrained
condition
Area
PA
(LG + 0.5LA)γsKA
0
LABD
PP
(LG + 0.5LA)γsKP
2cu
LABD
S1
LGγs tan δ
αcu
BWBD
S3
(LG + 0.5LA)γs K tan δ
αcu
2LABW
Value of S1 should be calculated based on the backfilled soil properties.
L5.2 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.
COPYRIGHT
199
AS/NZS 7000:2016
L5.3 Rock anchors
Where firm drillable rock is encountered within 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 + margin as recommended by manufacturer.
If cement grout is used, the hole diameter should be large enough to enable the grout
column to be injected and compacted.
Adequate corrosion protection should be applied to the zone above the rock to 300 mm
above ground. Concrete encasement can provide a suitable means of corrosion protection.
Uplift capacity of the anchorage should be based on geotechnical design using the rock’s
ultimate bond stress and the capacity reduction factor.
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Where possible the installed anchors should be proof-tested to their designed load capacity.
L6 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 of the driven steel piles could be performed in accordance to AS 2159.
L7 CATHODIC PROTECTION
Consideration should be given in the design process to the inclusion of an appropriate
cathodic protection system where aggressive soil conditions that could adversely affect the
design life of the footing may exist. Such systems can be of the sacrificial anode or
impressed current types.
COPYRIGHT
AS/NZS 7000:2016
200
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
L8 REFERENCES
1
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., Model tests with
transversally loaded rigid piles in sand.
2
IEEE Std 691—2001 Guide for Transmission Structures Foundation Design and
Testing.
3
Canadian Foundation Engineering Manual, 4th Ed.
4
Design Standard No. 10—Transmission Structures published by US Department of
the Interior, 1965.
5
Design of Piled Foundations ASCE Guide No. 1, 1993.
6
Foundation Installation An Overview CIGRE WG B2.07, 2006.
7
AS 2159—2009, Piling design and installation standard.
8
EPRI EL-2197, Vol 2—Comparative Study of Lateral Capacity Models.
9
AS 1726, Geotechnical site investigations.
10
Eurocode 4, EN1994-2, Design of composite steel and concrete structures. General
rules and rules for bridges.
COPYRIGHT
201
AS/NZS 7000:2016
APPENDIX M
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 documents listed in Paragraph M2 set out a standardized approach for construction and
maintenance work practices on overhead lines, in an effort to reduce further unnecessary
hazards for personnel moving between overhead line networks, and to provide uniform
work practices around Australia and New Zealand.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
M2 REFERENCE STANDARDS FOR CLIMBING AND WORKING AT HEIGHTS
AS/NZS
1891
1891.1
1891.2
1891.3
1891.4
Industrial fall-arrest systems and devices
Part 1: Harnesses and ancillary equipment
Part 2: Horizontasl lifeline and rail systems
Part 3: Fall-arrest devices
Part 4: Selection, use and maintenance
ENA
NENS 05
National fall protection guidelines for the electricity industry
EEA/NZ
Mobile Plant Use—ESI Employees (Guide)
Operation and Maintenance of Elevating Work Platforms (Guide)
COPYRIGHT
AS/NZS 7000:2016
202
APPENDIX N
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 include transmission or distribution towers/poles supporting high
voltage electrical conductors 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
N2 GENERAL REQUIREMENTS
The following factors should be considered for the upgrade of transmission structures:
(a)
Structure upgrade designs should be prepared and authorized 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 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
practices 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 clearances.
(e)
Fixture of new components to comply with updated OHS criteria for personnel
access.
(f)
Adding of new/larger telecommunication equipment.
COPYRIGHT
203
AS/NZS 7000:2016
N4 STRUCTURAL ASSESMENT
The appropriate stress analysis of a transmission tower requires calculation of the total
forces in each member of the tower under action of a 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 was originally designed. If the steel
material property and member properties are not documented, material testing and careful
engineering assessment is required. The designer should prepare documents for such
material testing and engineering assessment that should form an integral part of the
structural upgrade proposal.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Field inspection is a prerequisite 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
re-examined 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 carry out a comprehensive structural analysis of the transmission
structures considered for upgrading prior to any fieldwork, 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 trialling of options without design.
N7 STRUCTURE UPGRADE
N7.1 Lattice steel structure upgrade
N7.1.1 General
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.
N7.1.2 Tension member upgrade
The strength of a tension member can be achieved by replacing the existing member with a
stronger member or by adding an additional 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.
COPYRIGHT
AS/NZS 7000:2016
204
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 be taken into consideration for re-assessment 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 joints 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 the splice angle at the circumference with fillet seams to the
supplemented sections in the workshop and after galvanizing 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. See Paragraph N7.1.3 for connection details and
Paragraph N7.1.4 for load transfer between old and new members.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
N7.1.3 Compression members upgrade
The strength of compression members can be increased by reducing their unsupported
length or improving the end restraint.
The unsupported length can be reduced by inserting additional redundant members or
changing the redundant pattern.
Increasing the number of bolts at the end of single bolted members should change the endrestrained condition of compression members, which in turn should increase the
compression strength.
Addition of a new member should also increase compression strength of members. See
Paragraph N7.1.1 for the requirement of such modification. However, the sub-members
should have to be bolted in such a way that the composite member can be treated as a single
member (i.e. fully composite section).
T-section should have an improved slenderness ratio and hence, changing a compression
member to that profile (especially to increase the diaphragm strength by providing T-shaped
horizontal edge member) should increase the compression strength. (See Figure N1).
COPYRIGHT
205
0. 5
L
0. 5
AS/NZS 7000:2016
L
L
Y
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
X
NOTE: Critical slenderness ratio should be the maximum of 0.51/rxx and L/ryy.
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.
See Paragraph N7.1.3 for connection details and Paragraph N7.1.4 for load transfer between
old and new members.
N7.1.4 Connection upgrade and consideration in connection design
Connections can be upgraded by the use of high strength components. Use of additional
bolts at a joint should also increase the connection capacity.
Special attention should be given while designing connections between supplemented and
existing angle sections. The connection between old member and supplemented member
should 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 db, where db is the diameter of hole. The connection between existing members
and the supplementing member may be designed as non-slip joint. However, due care
should be given to verify the bolt pre-tension and the faying surface condition at site to
ensure the requirements considered during design are properly implemented. The slip factor
should 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.
N7.1.5 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 stiffness. 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 be taken during design to account for such an effect arising from
the installation condition. It is essential to confirm minimum relative movement of
sub-members of the newly formed compound member to ensure balanced load distribution.
COPYRIGHT
AS/NZS 7000:2016
206
N7.1.6 Guying of structures
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 system
caused by variations in initial installed tension, foundation movement or 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 factors such as relaxation of individual guys should be
considered;
(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 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 earthing requirements for the guy cable are covered in Clause 10.7.
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—
(i)
the termination fittings of the guy to allow coarse and fine length adjustment;
(ii)
tension measurement of the installed guys (by vibration frequency, mechanical
tensiometer, measurement of sag);
(iii) temporary removal of load to allow adjustment of the length; and
(iv)
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 or as
structural components—
(A)
if the guying system is designed as continuation of the conductors using conductor
hardware then allowance should be made for broken cables and attachments;
(B)
if the guying system is designed as a structural component the guy fittings should
have suitable working load limit (WLL) markings and be selected in accordance with
the WLL under everyday tension (EDT) and WLL*3 under ultimate loads. The
designer should check that the selected components have an ultimate capacity of at
least 5*WLL; and
COPYRIGHT
207
(C)
AS/NZS 7000:2016
[as alternate of (B)] if the guying system is designed as a structural component;
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.
Pre-tension 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—
(1)
pre-tension values; or
(2)
a tensioning sequence controlled by the pole top displacement.
The minimum pre-tension 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
Pre-tensioning 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 Pole upgrade
N7.2.1 Timber pole structure upgrade
The actual condition of a timber pole (including loss of section due to termite attack or rot)
should be taken into consideration when the overhead line or a part of it is to be upgraded.
This should also consider further deterioration over time.
Pole reinforcement may be used to extend the service life.
Various strengths and types of pole reinforcement 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 suffers further deterioration.
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 galvanizing.
Galvanized steel in direct contact with soils will not have significant life unless installed 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.
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.
COPYRIGHT
AS/NZS 7000:2016
208
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 this region is
required in order to extend the service life of the structure.
N7.2.2.3 Slip joints and internal surface protection
All 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 this needs to be checked over the life of the line.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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
Limited scope exists to upgrade the design capacity of these structures apart from 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 expected to be similar to concrete poles.
N8 FOUNDATION UPGRADE
Increased reaction from structures for the purposes stated in Paragraph N3 should be
transferred safely to the existing foundation system. The designer should 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 stabilizing). Other methods may
include enlarging the footing bearing area or installing tie beams between individual
footings.
New foundations can be installed to transfer higher loads from super structure and after
completion of the new foundation construction, the structure can be repositioned onto the
new foundation. In such case, the old foundation may be abandoned or may be used as a
part of the new foundation.
The designer should prepare the temporary load transfer arrangement as well as sequential
working procedures required for the safe strengthening of the existing foundation
system/construction of a new foundation or safe re-positioning of the structure onto the new
foundation.
COPYRIGHT
209
AS/NZS 7000:2016
Appropriate geotechnical investigation is required prior to any foundation modification or
installation of new foundation for increased load transfer. The designer should carry out
appropriate investigation to predict any potential stability hazard to an existing foundation
that may arise while constructing a new foundation or modifying an existing foundation
causing soil disturbance.
N9 MODIFICATION OF LATTICE STEEL STRUCTURE
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Lattice steel structures can be strengthened by means of the 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.
(g)
Upgrade 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 the following measures:
(g)
Adding stays.
(h)
Adding pole reinforcement for wooden poles.
(i)
Doubling up poles, sometimes even a small pole may be added.
(j)
Inserting the steel section on the base of a wooden pole to increase height.
(k)
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 consider the following aspects:
(a)
Production of construction and maintenance procedures complying with the design
assumptions and requirements.
(b)
All potential constraints are documented.
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.
COPYRIGHT
AS/NZS 7000:2016
210
APPENDIX O
WATER ABSORPTION TEST FOR CONCRETE
(Informative)
O1 SCOPE
This Appendix sets out the method for the determination of the water absorptive property of
concrete poles, in a batch of poles.
NOTE: The test method is based on AS 4058.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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, should not be less than 14 days nor greater than 28 days. The poles should not
have been subjected to any previous testing, which would affect the absorptive properties of
the concrete. The area of the surface from which the test specimens are to be cut should 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 × 10 mm2 and 1.5 × 10 mm2.
NOTE: A cylindrical specimen, made by cutting radially through the wall with a coring bit of
115 mm diameter, or 125 mm nominal diameter, would satisfy these area requirements.
The cut surfaces of the specimen should be ground smooth, have any latence removed and
the specimen kept in a damp condition until tested.
COPYRIGHT
211
AS/NZS 7000:2016
O6 TEST PROCEDURES
O6.1 General
The test should be carried out when the age of the concrete in the specimen is not greater
than 28 days.
NOTE: The ability of concrete to absorb water diminishes with increasing time after casting 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 (m 1)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 m0. 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 h 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 (m 2)
At the end of the immersion procedure, remove the specimen from the bath, allow it to
drain for not more than 1 min, and 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 (m2), 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.
COPYRIGHT
AS/NZS 7000:2016
212
O7 CALCULATIONS
The absorption of each test specimen should be calculated from the following equation:
k wj =
(m2 − m1 ) × 100
( m1 − m3 )
. . . O1
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
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
For each batch of poles for which water absorption tests are taken, the following records
should 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, m2 and m3;
(ii)
the calculated value of kwj; 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 should 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 kwj for the batch.
(d)
A statement as to whether or not these values satisfy the criteria given in
Paragraph I5.2.
COPYRIGHT
213
AS/NZS 7000:2016
APPENDIX P
INSULATION GUIDELINES
(Informative)
P1 INSULATION COORDINATION BASICS
Pollution flashovers can occur under wet or high humidity conditions. An overhead line
should be designed to avoid a power frequency flashover. Even if the insulation can
withstand the initial flashover without damage, upon reclosure of the line there is every
likelihood 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 provides guidance on the selection of insulators in
contaminated environments.
TABLE P1
GUIDE FOR SELECTING INSULATORS IN
CONTAMINATED ENVIRONMENTS
Contamination
severity
ESDD range (1)
Minimum nominal specific
creepage distance (2, 3)
g/m
mm/kV
0 to1.2
16
Light
(1)
(2)
(3)
Medium
1.2 to 2.0
20
Heavy
2.0 to 3.0
25
Very heavy
Above 3.0
31
ESDD is the equivalent salt deposit density.
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.
Consideration should be given to increasing the creepage distances in
areas where there are long periods without rainfall or located 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 (16 × 33)
Number of discs = 528/300
= 1.76 → 2 discs
The pollution performance of insulators can also be improved with the use of 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.
COPYRIGHT
AS/NZS 7000:2016
214
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 cross-arm, and
cross-arm to pole.
P3 DESIGN
FOR
SWITCHING
PERFORMANCE CONSIDERATIONS
SURGE
DESIGN
AND
LIGHTNING
A good reference for 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 two 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 flashovervoltages 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 flashovervoltage is 0.8 times the lightning impulse flashovervoltage.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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
P4.1 General
The two main classes 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.
P4.2 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 between manufacturers who have to
balance the requirements of having an aerodynamic shape to attract fewer 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 430 mm. This is
a 40% improvement in leakage distance over the standard disc. The additional creepage
length is gained by having deeper skirts. This additional creepage length is gained without
increasing the coupling length of the string, thereby maintaining electrical clearances to the
structure. It is common practice to install fog profile insulators in heavy to extreme
contamination areas. This is acceptable for marine or industrial environments that 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 to be used.
P4.3 Ceramic pin, shackle and posts
Ceramic pin, shackle and post 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 insulator. Pin insulators
usually have less creepage length compared to the post types but can be designed with
larger skirts to handle heavy contamination conditions.
COPYRIGHT
215
AS/NZS 7000:2016
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.
P4.4 Composite long rod and line post insulators
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Composite insulators are made with a fibreglass 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 hydrophobicity 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. 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).
Composite 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
them 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.
COPYRIGHT
AS/NZS 7000:2016
216
APPENDIX Q
CONDUCTOR BLOW OUT AND INSULATOR SWING
(Informative)
Q1 METEOROLOGICAL ASSUMPTIONS
The estimation of swing angles may be made using a simplified deterministic approach or a
detailed procedure using meteorological records. The latter method should be used when
greater precision is required or where unusual and/or extreme local conditions prevail.
Clause 2.2.1.4 provides design wind pressures for the simplified procedure.
Q2 SUSPENSION INSULATOR SWING
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The swing angle (φ from vertical) of a suspension insulator string can be estimated using
the following formula.
⎛
F
⎛θ ⎞ ⎞
⎜ PdS w + 2 +2 H sin ⎜ 2 ⎟ ⎟
⎝ ⎠⎟
ϕ = tan −1 ⎜
Wi
⎜
⎟
Wc +
⎜
⎟
2
⎝
⎠
. . . Q1
where
P = reference wind pressure Pascal (Pa)
d = overall conductor diameter in metres (m)
Sw = wind span affecting the insulator string in metres (m)
F = wind load on insulator string in Newtons (N) (See Paragraph B5.4)
Wc = effective conductor weight in Newtons (N)
= weight span (m) x weight per unit length in Newtons per metre (N/m)
Wi = weight of insulator string Newtons (N)
H = horizontal component of conductor tension Newtons (N)
θ = conductor deviation angle (could be different from the line deviation angle)
The insulator swing may be different at the supports at either end of the span where
different wind span to weight span ratios may exist.
The values for d, H and Wc will need to be multiplied by the number of sub-conductors for
bundled phases. The values of F and Wi will need to be multiplied by the number of strings
where multiple suspension strings are used.
COPYRIGHT
217
AS/NZS 7000:2016
Q3 CONDUCTOR BLOWOUT
The swing angle (φc from vertical) of a phase conductor in a span can be estimated using
the following formula.
⎛ Pd w ⎞
⎟
⎝ w ⎠
ϕc = tan −1 ⎜
. . . Q2
where
P = reference wind pressure in Pascals (Pa)
d = conductor diameter in metres (m)
w = distributed conductor weight in Newtons per metre (N/m)
This formula also applies for bundled phases if the wind area of spacers is ignored and
shielding of the leeward sub-conductors is ignored.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Q4 COMBINED
BLOWOUT
SUSPENSION
INSULATOR
SWING
AND
CONDUCTOR
The horizontal conductor displacement (y) at any point in the span can be calculated using
the results produced by equations Q1 and Q2 as follows:
⎛ x1 ⎞
y = S sin ϕ c + I1 sin ϕ1 + ⎜
⎟ ( I 2 sin ϕ 2 − I1 sin ϕ1 )
⎝ x1 + x2 ⎠
. . . Q3
where
S = sag at point under consideration - measured in the inclined plane metres (m)
ϕc = angle of conductor swing (from vertical)
ϕ1 = angle of first insulator swing (from vertical)
ϕ2 = angle of second insulator (from vertical)
I1 = length of first insulator string in metres (m)
I2 = length of second insulator string in metres (m)
x1 = distance from point to first support in metres (m)
x2 = distance from point to second support in metres (m)
Figure Q1 graphically depicts these variables.
Equation Q3 assumes that the wind is uniformly distributed over the entire ruling span
section and that no significant longitudinal insulator swing occurs. In reality the wind is
spatially and randomly distributed and the wind pressure will vary along the conductor,
resulting in possibly larger values of blow out than predicted. This is particularly so for
localized high intensity winds where slack will be pulled from adjacent spans and put into
the span experiencing the greater wind pressure. However blow out under ultimate wind
conditions is not usually calculated. Generally the conductor blow out is calculated using a
wind pressure derived from a return period conforming to a serviceability limit and with an
averaging period of 5 to 10 minutes. Such calculations ensure that electrical clearance
infringements to vegetation and other structures are uncommon occurrences.
COPYRIGHT
AS/NZS 7000:2016
218
l2
l2
M2
B l owo u t rotati o n a x i s
Mc
S
I1
I1
M1
x1
x2
y
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
T R A N SV ER S E V IE W
LO N G I T U D IN A L V IE W
FIGURE Q1 COMBINED SUSPENSION INSULATOR SWING AND
CONDUCTOR BLOWOUT
COPYRIGHT
219
AS/NZS 7000:2016
APPENDIX R
CONDUCTOR SAG AND TENSION
(Informative)
R1 GENERAL
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 tension excursions are in
the non-linear stress strain regime. This Appendix deals with the linear stress strain model.
The linear stress strain model may be employed using the modulus of elasticity determined
in accordance with Appendix V. For non-linear stress strain design, two methods are
commonly used and are the ‘graphical’ and ‘strain summation.’
The non-linear and linear stress strain models have been analysed, compared and described
in some detail [1]. To employ the non-linear stress strain detailed knowledge of the
particular conductor stress strain loading and unloading characteristic as detailed in
Appendix V is required.
In addition to whether the non-linear or linear methods are used two methods are employed
for each method to determine the conductor tensions and are either the equivalent (ruling)
span theory [2] or the complex finite element analysis [3]. The equivalent span theory
explained in Paragraph R4 may be used for the majority of overhead line designs.
R2 TERMINOLOGY
The geometry of an inclined span is given in Figure R1.
V2
T2
Y
( x 2, y 2)
I
h
T1
H
S2
D
V1
( x 1 , y 1)
( x 3 , y 3)
(0,0)
X
S1
L
FIGURE R1 INCLINED SPAN GEOMETRY
COPYRIGHT
H
AS/NZS 7000:2016
Deadend span
Inclined span
Level span
Ruling span
Sag
Section
Suspension
span
Tension
constraint
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Transition
span
220
A span where both ends are terminated.
A span where the conductor supports are at different levels.
A span where the conductor supports are at the same level.
A hypothetical level deadend span used to model the tension behaviour of a
section.
The maximum vertical departure of the catenary from a chord joining the
support points (approximately mid span).
That portion of an overhead line between strain structures consisting solely
of intermediate structures for which the ruling span concept is valid.
A span where either or both conductor supports are free to swing
longitudinally along the line.
The maximum allowable horizontal component of conductor tension for a
given loading condition. The tension constraint may vary with the ruling
span length.
The ruling span where two tension constraints produce identical unstressed
conductor lengths. The conductor tension for ruling spans above and below
the transition span will be controlled by different tension constraints.
R3
A
Aa
As
C
Ch
Cv
d
D
E
g
h
H
VARIABLES
= total conductor cross-sectional area
= cross-sectional area of the aluminium component of a conductor
= cross-sectional area of the steel component of a conductor
= resultant catenary constant
= horizontal component of the catenary constant using Wh
= vertical component of the catenary constant using Wv
= overall conductor diameter exposed to transverse wind
= conductor sag
= modulus of elasticity of the load bearing material
= gravitational acceleration (9.81)
= height difference between conductor supports (y2 − y1)
= horizontal component of conductor tension T
I
= chord length between conductor supports
L
Lh
Lr
Lv
m
P
r
S
S0
t
T
Ta
V
=
=
=
=
=
=
=
=
=
=
=
=
=
(
L2 + h 2
)
span length (x2 − x1)
wind span for a structure
equivalent or ruling span of a section
weight span for a structure
conductor unit mass including covering or insulation
transverse component of wind pressure
radial ice thickness
stressed conductor length
unstressed conductor length at 0°C
average conductor temperature
tangential or axial conductor tension
average axial conductor tension
vertical component of tension T
COPYRIGHT
(mm2)
(mm 2)
(mm 2)
(m)
(m)
(m)
(m)
(m)
(MPa)
(m/s 2)
(m)
(N)
(m)
(m)
(m)
(m)
(kg/m)
(Pa)
(m)
(m)
(m)
(°C)
(N)
(N)
(N)
221
W = resultant or inclined distributed conductor load
Wh = transverse component of distributed conductor load (wind)
Wv = vertical component of distributed conductor load (weight)
∝ = coefficient of linear expansion
Δ = conductor slack
ε = plastic strain from strand settling and metallurgical creep
π = 3.14
ρ = ice density
σ = tensile stress
AS/NZS 7000:2016
(N/m)
(N/m)
(N/m 1)
(1/°C)
(m)
(mm/km or με)
(kg/m3)
(MPa)
R4 MODELS
A flexible, inelastic conductor with constant load (W per unit of arc length) suspended
between supports assumes the shape of a catenary—
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
H
⎛
⎛x⎞ ⎞
y = C ⎜ cosh ⎜ ⎟ − 1⎟ where the catenary constant C =
W
⎝C⎠ ⎠
⎝
. . . R1
An approximation of the catenary is the parabola which uses a constant load (W per
horizontal unit length)—
y=
x2
2C
. . . R2
For span lengths less than about 0.7 C, or sags less than about 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 need to be
modified for temperature, elasticity, wind pressure, ice weight and age of the conductor.
R5 EQUIVALENT SPAN
The equivalent (ruling) span, also known as the ruling 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.
The ruling span concept can only model a uniformly loaded section, that is, where identical
wind and/or ice span exists on all spans in the section.
It is assumed that the insulator is free to swing along the line and the insulators are long
enough to equalize the tension in adjacent spans without transferring any 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 the time of
stringing conductor).
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 approximately equal, then there is little difference in tension
across the fixed attachment point under identical loading conditions in each span.
For cases where the ruling span method does not accurately predict sags and tensions, the
exact solution will lie between the conductor tension results produced by using the ruling
span method where insulators are assumed to move longitudinally to equalize tensions; and
assuming every structure in the section is a strain structure with a fixed attachment point.
COPYRIGHT
AS/NZS 7000:2016
222
The actual ruling span can only be calculated after the structure locations are determined.
Therefore an assumed value for the ruling span is made before spotting the structures. In
most cases, the actual ruling span should be greater than or equal to the assumed ruling
span to ensure that design clearances are met. However, the situation sometimes arises for
large ruling spans when the controlling constraint is associated with a heavy loading
condition and the tension decreases with increasing ruling spans at the maximum operating
temperature. 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
Lr =
∑ L3i
i =1
n
∑ Li
for level spans
. . . R3
i =1
n
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
L4
∑ Ii
i
Lr =
i =1
n
for inclined spans
. . . R4
∑ Ii
i =1
where
Ii =
L2i + hi2 = the chord length between the supports of span
Li = the horizontal span length of span
i
i
hi = the support height difference of span
i
n = the number of spans in the section between strain structures
For a single level, dead-end span the ruling span is Lr = L. However, for a single inclined
dead-end span, Lr = L2/I.
The ruling span formula is derived assuming that the conductor hangs in a vertical plane.
When transverse wind is applied, the conductor hangs in an inclined plane which effectively
changes the span length and support height difference in that plane. The ruling span formula
for inclined spans (R4) changes with the conductor blow out angle. The tension change
formula (R18) does not allow for a ruling span that changes from one loading condition to
another. It is accepted practice to use the level span formula (R3) for deriving the ruling
span that is subsequently used for tension change calculations.
For all blowout angles (up to 90°C) and for sections where the average ratio of h/L is less
than 0.2, the true ruling span will be within ±2% of the ruling span calculated assuming
level spans (R3).
In general, for inclined spans under wind conditions, ruling span Equation R3 provides a
better approximation for tension.
To overcome the limitations of the ruling span method, a finite element model of the
conductor and structure system is required. Usually the structures are modelled using
stiffness matrices, however the ideal model is one that includes the structural elements.
COPYRIGHT
223
AS/NZS 7000:2016
R6 LOADING CONDITIONS
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:
Wh = P ( d + 2 r )
. . . R5
Wv = g ( m + ρπ r (d + r ))
. . . R6
where ρ ranges from about 400 kg/m 3 for wet snow to 900 kg/m 3 for ice.
The resultant distributed load is the vector sum of Wh and Wv
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
W = Wh2 + Wv2
. . . R7
The catenary constants C, Ch and Cv are functions of W, Wh and Wv respectively. Ch is used
for conductor swing calculations, Cv is used to calculate vertical clearances and C is used
for calculating tension changes.
Longitudinal and yawed wind loading and point loads such as cable chairs, droppers, strain
insulator strings, structure deflection and aircraft warning spheres require analytical tools
not covered by this Appendix.
R7 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. For information on
everyday tension see Appendix Y.
(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 may be carried out 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 usually applied since strand settling and metallurgical creep are virtually
completed in that period.
The controlling constraint is the most restrictive tension constraint, producing the largest
sags and the least tensions for any given loading condition. For a given ruling span usually
only one tension constraint controls (or limits) the tensions for all other loading conditions.
At the transition ruling span, two tension constraints produce identical values of unstressed
lengths, that is there are two controlling constraints.
COPYRIGHT
AS/NZS 7000:2016
224
A tension constraint can alternatively be expressed as a catenary constant, aluminium stress,
support tension, sag or an amount of slack. Each of these alternatives can be converted to a
horizontal tension as follows:
(i)
Catenary constant (C)
H=W×C
(ii)
. . . R8
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 + 3As)
. . . R9
For a homogeneous conductor
H = σA
. . . R10
(iii) Tangential tension (T) at a support (based on the parabola and a level span)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
2
2
T
⎛ T ⎞ (WLr )
H= + ⎜ ⎟ −
2
8
⎝2⎠
(iv)
Sag (D) (based on the parabola)
H=
(v)
. . . R11
Wv L2r
8D
. . .R12
Slack Δ
H =W
L3r
24Δ
. . . R13
The advantages of constraining the tension based on slack are as follows:
(A)
The specified amount of slack is available when required to uncouple the hardware
fittings when changing strain insulator strings. This is important for short spans.
(B)
The tension reduces as the ruling span length shortens and this makes aesthetic short
span geometry.
(C)
Light duty strain structures may be used for short spans with only a small penalty in
terms of increased structure height.
For a given ruling span the tension constraint producing the longest unstressed conductor
length as given by Equation R14 is the controlling constraint. The conductor length at 0°C,
under no tension and at an age when the creep strain is zero is—
S0 =
S
1+
Ta
+ αt + ε
EA
. . . R14
where the stressed conductor length for the catenary is
⎛ L ⎞
S = 2C sinh ⎜ r ⎟
⎝ 2C ⎠
. . . R15
and for the parabola is
S = Lr +
L3r
24C 2
. . . R16
COPYRIGHT
225
AS/NZS 7000:2016
It is common practice to assume that Ta ≈ H; however, Ta is evaluated more accurately by
Equation R40 for the catenary and R57 for the parabola.
R8 TENSION CHANGES
The tension change or change of state equation relates the unstressed conductor length for
two different loading conditions. The relationship between the stressed and unstressed
length is based on Hooke’s law for linear elastic materials. Any thermal strain or plastic
strain (creep and strand settling) is modelled by a strain translation of the linear stress/strain
curve. Therefore the tension change equation only applies for conductors behaving
elastically as shown in Figure R2.
STRESS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Linear model
ove r e s ti m ate s
te n s i o n s
Initial modulus
curve
Fi n a l m o d u l u s s l o p e
L i n e a r m o d e l a c c u r a te l y
e s ti m ate s te n s i o n s
L i n e a r m o d e l u n d e r e s ti m ate s te n s i o n s
STRAIN
FIGURE R2 LINEAR ELASTIC NON HOMOGENOUS CONDUCTOR MODEL
For one loading condition such as the controlling tension constraint Hi is defined. For the
other loading condition the tension Hf is desired and is solved using the tension change
equation.
S0 =
Si
Hi
+ α ti + ε i
1+
EA
=
Sf
Hf
+ α tf + ε f
1+
EA
. . . R17
The value of S0 is known because by definition the controlling constraint is the tension
constraint producing the longest value of S0. Note that Sf is a function of Hf and can be
evaluated using either the catenary Equation R15 or the parabolic Equation R16.
When the parabola is used the tension change equation becomes—
H 3f + aH 2f − b = 0
. . . R18
where
⎛ W 2 L2
⎞
a = EA⎜⎜ i r2 + α (tf − ti ) + (ε f − ε i )⎟⎟ − H i
⎝ 24H i
⎠
b=
EAW f2 L2r
24
COPYRIGHT
AS/NZS 7000:2016
226
In practice, there is negligible difference between the results from tension change equations
derived from the catenary and that derived from the parabola.
When the plastic strains are ignored, Equation R18 is called the time independent tension
change equation.
R9 SAGGING TENSIONS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
For the purpose of determining sagging tensions, the variables with subscript ‘f’ refer to the
controlling constraint whilst variables with subscript ‘i’ 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 which is usually 10 years. The creep
strain εi occurs prior to sagging.
The plastic strain is the sum of metallurgical creep and strand settling. Guidance on
metallurgical creep strain can be obtained from references provided in Appendix U. The
strand settling strain can be approximated from the stress strain curve by subtracting the
elastic strain from the initial composite strain. A plastic strain allowance may 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.
It is common practice to convert the difference in creep strain ( εf – εi) to an equivalent
thermal strain ( αtc) 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 R18 with
εf = εI = 0 and the initial sags and tensions are determined by applying a negative
temperature correction of tc =
εf − εi
to the final sags and tensions.
α
The following methods may be used to compensate for plastic strain:
(a)
A clearance buffer is added to the statutory ground clearance and new conductor is
sagged to the final (10 year) values. The disadvantage of this method is that the
magnitude of the buffer depends upon the span lengths. Normally a buffer is also used
for errors that arise from surveying, design and construction. This method is not
recommended for long spans unless additional clearance is provided.
(b)
Add a temperature buffer to the maximum operating temperature and provide final
(10 year) sags for stringing new conductor. This method may provide excess ground
clearance when a non-linear ACSR model is used. That is because the design
temperature is not the maximum operating temperature and high temperature sags are
larger when aluminium goes into compression. This method results in the final actual
tension being below the final design tension, thus producing a sub-optimum solution
for long spans.
(c)
Prestress the conductor prior to sagging with the final (10 year) values. The high
prestress tension is used to quickly remove future metallurgical creep and strand
settling. Its disadvantage is that it reduces the structural safety margin during the
stringing operation.
(d)
Over tension the conductor by providing initial (1 h) sag values or by using a negative
temperature compensation value along with the final sags (as described above). The
disadvantage of this method is that it is difficult to sag the entire section quickly
enough to avoid difficulties resulting from the high initial rate of creep. It also
exposes the conductor to a higher risk of aeolian vibration damage during the early
life of the line.
COPYRIGHT
227
AS/NZS 7000:2016
A combination of methods (c) and (d) provides an acceptable solution; however the method
requires information regarding the tension and temperature experienced by the conductor
during the pre-sag period.
R10 PHYSICAL PROPERTIES
The ruling span concept assumes that the tension in each span of the ruling span section is
the same. Once the conductor tension has been determined for a particular load case and
conductor age using the ruling span for the section, the physical characteristics of each span
in the section may be determined using either inelastic catenary or inelastic parabolic
equations.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
R11 CATENARY EQUATIONS
x1 = C tanh−1
⎛
⎜
h
⎛h⎞ L
−1
⎜ ⎟ − = C sinh ⎜
⎝S⎠ 2
⎜ 2C sinh L
2C
⎝
⎞
⎟ L
⎟−
⎟ 2
⎠
. . . R19
x2 = C tanh−1
⎛
⎜
h
⎛h⎞ L
−1
⎜ ⎟ + = C sinh ⎜
⎝S⎠ 2
⎜ 2C sinh L
2C
⎝
⎞
⎟ L
⎟+
⎟ 2
⎠
. . . R20
2
L ⎞
⎛
2
S = S1 + S 2 = ⎜ 2C sinh
⎟ +h
2
C
⎝
⎠
. . . R21
S1 = − Csinh
x1
= weight span contribution to structure 1
C
. . . R22
S2 = − Csinh
x2
= weight span contribution to structure 2
C
. . . R23
S
= wind span contribution to structure 1 and structure 2
2
. . . R24
Δ =S−I
. . . R25
V1 = H sinh
x1
= Wv S1
C
V2 = − H sinh
. . . R26
x2
= WV S2
C
. . . R27
x
⎛
⎞
y1 = C ⎜ cosh 1 − 1⎟
C
⎝
⎠
. . . R28
x
⎛
⎞
Y2 = C ⎜ cosh 2 − 1⎟
C
⎝
⎠
. . . R29
T1 = H cosh
x1
= H + Wy1
C
. . . R30
T2 = H cosh
x2
= H + Wy2
C
. . . R31
T2 − T1 = W × h
. . . R32
COPYRIGHT
AS/NZS 7000:2016
228
T2 + T1 =
WS
tanh
. . . R33
tanθ1 = − sinh
x1 S1
=
C C
. . . R34
tan θ2 = − sinh
x2 S2
=
C
C
. . . R35
x3 = Csinh−1
D≈
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
L
2C
S
h
(approximately mid span)
L
L
2C sinh
2C
L
L
⎛
⎞ IC ⎛
⎞
C ⎜ cosh
− 1⎟ =
− 1⎟
⎜ cosh
2C ⎠ L ⎝
2C ⎠
⎝
L
⎛
⎞
D = C ⎜ cosh
− 1 ⎟ (for a level span)
2C ⎠
⎝
⎛ S 2 + h2
L L ⎞
sinh + ⎟
⎜ 2
2
−
S
h
C
C ⎠
⎝
Ta =
CH
2S
Ta =
HL ⎞
1⎛
⎜T +
⎟ (for a level span where T1 = T2 = T )
S ⎠
2⎝
. . . R36
. . . R37
. . . R38
. . . R39
COPYRIGHT
. . . R40
229
AS/NZS 7000:2016
R12 PARABOLIC EQUATIONS
x1 =
Ch L
= weight span contribution to structure 1
−
L
2
. . . R41
x2 =
Ch L
= negative weight span contribution to structure 2
+
L
2
. . . R42
L
= wind span contribution to structure 1 and structure 2
2
. . . R43
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.
S=I+
L4
24C 2 I
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Δ=S−I =
. . . R44
L4
8D 2
=
24C 2 I
3I
. . . R45
Wv L Hh
−
L
2
. . . R46
V1 = −Wvx1 =
V2 = −Wvx2 =
Wv L Hh
+
2
L
. . . R47
y1 = D +
h2
h
−
16 D 2
. . . R48
y2 = D +
h2
h
+
16 D 2
. . . R49
T1 =
H
C
x12 + C 2
. . . R50
T2 =
H
C
x22 + C 2
. . . R51
tan θ1 =
x1 h − 4 D
=
C
L
. . . R52
tan θ 2 =
x2 h + 4 D
=
C
L
. . . R53
x3 =
Ch
(mid span) (mid span)
L
. . . R54
D=
L2
(independent of h )
8C
. . . R55
Ta =
H ⎛ I2
L3 ⎞
+
⎜
⎟
S ⎝ L 12C 2 ⎠
. . . R56
Ta =
HL2
HL3
+
(for h = 0)
S
12SC 2
. . . R57
L⎞
⎛
= H ⎜2− ⎟
S⎠
⎝
COPYRIGHT
AS/NZS 7000:2016
230
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
R13 REFERENCES
1
CIGRE SCB2.12.3 ‘Sag Tension Calculation Methods for Overhead Lines’, CIGRE
Technical Brochure No. 324, June 2007.
2
BOYSE, C.O. and SIMPSON, N.G. ‘The Problem of Conductor Sagging on Overhead
Transmission Lines’, Journal of the IEE, Vol 91, Pt II, Dec 1944, pp 219–231.
3
BARRIEN, J., Precise Sags and Tensions in Multiple Span Transmission 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.
5
NIGOL, O. and BARRETT, J.S., Characteristics of ACSR Conductors at High
Temperatures and Stresses, IEEE Transactions on Power Apparatus and Systems,
Volume PAS-100, Issue 2, February 1981, pp 485–493.
6
MOTLIS, Y., BARRETT, J.S., DAVIDSON, G.A., DOUGLASS, D.A., HALL, P.A.,
REDING, J.L., SEPPA, T.O., THRASH JR., F.R., WHITE, H.B., Limitations of the
ruling span method for overhead line conductors at high operating temperatures,
IEEE Transactions on Power Delivery, Volume 14, Issue 2, April 1999, pp 549–560.
COPYRIGHT
231
AS/NZS 7000:2016
APPENDIX S
CONDUCTOR TEMPERATURE MEASUREMENT AND
SAG MEASUREMENT
(Informative)
S1 CONDUCTOR TENSION MEASUREMENT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Line design is based upon accurately knowing the conductor tension; loading for structural
design; clearance for electrical design; fatigue for mechanical design. Conductor tension is
set when sagging the conductor and conductor tension is checked when analysing an
existing line. Even though conductor tension can be measured directly using a dynamometer
in series (or parallel) with the conductor, this method has many practical disadvantages.
Conductor sag is the most accurate indicator of conductor tension. There are many methods
of setting or measuring conductor sag, some of which are as follows:
(a)
Sightboard method.
(b)
Tangent method.
(c)
Offset method.
(d)
Clino method.
(e)
Wave method.
(f)
Swing method.
Analytical equations can be derived for these methods depending on the operation being
performed; the sag is known for the ‘sagging’ operation whereas the sag is unknown for the
‘checking’ operation.
S2 CONDUCTOR TEMPERATURE MEASUREMENT
The actual temperature of the conductor should be measured when sagging the conductor to
avoid conductor over-tensioning or loss of ground clearance (under-tensioning).
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 a 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. A temperature correction may be required to allow for the inelastic stretch of the
conductor over its lifetime.
The conductor temperature measurement of energized lines requires a contact thermometer
(thermocouple) mounted on an insulated hot stick of suitable length. Alternatively the
temperature needs to be calculated from ambient conditions, assumptions about the surface
condition of the conductor and load current. This method provides a range of probable
temperatures and needs to be calculated afterwards.
S3 CONDUCTOR IDENTIFICATION
Correct conductor identification is important because its tension is proportional to its
distributed mass. For new lines, the conductor should be readily identifiable. Where the
records are missing or inaccurate for existing lines, the conductor diameter and the material
of the outer stranding may provide some clues. Conductor gauges with limited diameter
ranges are available for mounting on insulated hot sticks.
COPYRIGHT
AS/NZS 7000:2016
232
S4 SIGHT BOARD METHOD
To produce the required sag, a sight board is fitted at the required distance (usually D)
below the point of attachment at each end of the span and the conductor is tensioned until
the tangent of the catenary is in the line of sight between the two boards. A telescope with
crosshairs is used for better accuracy. If the conductor temperature varies after the
sightboards are erected, then Equation S1 (based on the parabola) is used to correct the
sightboard location at the sighting end of the span without having to adjust the location of
the target sightboard.
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 second conductor
attachment (distance B). See Figure S1.
B
D
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
A
FIGURE S1 THE SIGHT BOARD METHOD
⎛ A+ B⎞
D=⎜
⎟
2
⎝
⎠
2
. . . S1
where
D = conductor sag (midspan)
A = distance below the first conductor attachment
B = distance below the second conductor attachment
S5 TANGENT METHOD 1
This method is recommended for long spans where the sag is greater than the height of
either conductor attachment point above the ground. A theodolite is set up below the
conductor attachment at one end of the span and the angle of tangency to the catenary is
calculated for the required sag (see Figure S2). Alternatively the sag can be calculated by
solving the following equation (based on the parabola):
D
H2
H1
L E V EL
PL
100
L
FIGURE S2 THE TANGENT METHOD 1
COPYRIGHT
233
tan θ =
AS/NZS 7000:2016
4 H 1 D + H 2 − H1 − 4 D
L
. . . S2
where
θ = angle of tangency to the catenary
D = conductor sag (midspan)
H1 = vertical distance from the centre of the theodolite to the conductor attachment
H2 = far attachment height of conductor above the instrument height
L = span length
H1 can be measured using a rangefinder, height stick, tape measure or another theodolite.
This method should not be used where the point of tangency is less than 20% or greater
than 80% of the span length because of the sensitivity of sag to sighting errors.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
P = 50
H1
D
. . . S3
where
P = point of tangency expressed as a percentage of the span length (%)
S6 TANGENT METHOD 2
This method requires only a theodolite (see Figure S3). It is suitable for spans with large
sags.
xT
x1
D
H2
Low p oint
H1
T
L E V EL
PL 2
10 0
L2
L1
FIGURE S3 THE TANGENT METHOD 2
C=
L22
8D
(Catenary constant)
x1 =
C ( H 2 − H 1 ) L2
−
2
L2
(Distance from low point to first support)
x T = x 1 - L1 + L21 - 2x 1 L1 + 2CH1
(Distance from low point to point of
tangency)
COPYRIGHT
. . . S4
AS/NZS 7000:2016
234
tan θ =
P=
xT
C
(Slope of tangent)
100 ( xT - x1 )
L2
Nomenclature is the same as for tangent method 1.
S7 OFFSET METHOD
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The conductor sag can be determined by measuring three points on the conductor,
preferably as far apart as practical (see Figure S4). This is conveniently done using a
theodolite set up at approximately midspan and at an offset from the line such that vertical
angles to the conductor are comfortably read. Alternatively the points can be collected
using a differentially corrected GPS in conjunction with a height measuring stick or
rangefinder. Aerial laser surveying may also be used, but this technique collects multiple
conductor shots and so it is usually used with detailed computer modelling.
H2
D
H1
L E V EL
L1
L2
FIGURE S4 THE OFFSET METHOD
D=
L1 + L2 ⎛ H1 H 2 ⎞
⎜
⎟
+
4 ⎜⎝ L1 L2 ⎟⎠
. . . S5
where
D = conductor sag (midspan)
L1 = distance from centre shot to LH attachment
L2 = distance from centre shot to RH attachment
H1 = LH attachment height relative to the centre shot
H2 = RH attachment height relative to the centre shot
S8 HEIGHT STICK METHOD
A variation of the offset method occurs when the theodolite is set up underneath the
conductor i.e. with no offset (see Figure S5). In this instance the middle conductor
measurement requires a height above the instrument. This may be measured using a height
stick, rangefinder or another theodolite.
COPYRIGHT
235
AS/NZS 7000:2016
D
H2
H1
H
L E V EL
L2
L1
FIGURE S5 THE HEIGHT STICK METHOD
D=
L1 + L2 ⎛ H1 − H H 2 − H ⎞
⎜
⎟
+
4 ⎜⎝ L1
L2 ⎟⎠
. . . S6
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
where
D = conductor sag (midspan)
L1 = distance from centre shot to LH attachment
L2 = distance from centre shot to RH attachment
H
height of conductor above the instrument
(if measuring height above the ground, subtract the instrument height)
H1 = LH attachment height relative to the instrument height
H2 = RH attachment height relative to the instrument height
S9 CLINO METHOD
The gradients can be measured with an inclinometer (clino) (see Figure S6). Both gradients
should be positive unless there is uplift at one of the attachments. This method should only
be used to provide indicative values of sag. It will be difficult to accurately measure the
take-off angles at each attachment. This may be impossible for short spans, small sags or
high conductor attachments.
L
D
1
2
GROUND
FIGURE S6 THE CLINO METHOD
COPYRIGHT
AS/NZS 7000:2016
D=
236
L
(tanθ1 + tanθ2 )
8
. . . S7
where
D
= conductor sag (midspan)
L
= span length
tanθ1 = gradient to the point of tangency at one attachment point
tanθ2 = gradient to the point of tangency at the other attachment point
S10 WAVE METHOD
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Wave sagging relies on the speed at which a mechanical pulse propagates 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. The reflected pulse may be too weak much beyond three returns.
g⎛ t ⎞
D= ⎜ ⎟
32 ⎝ N ⎠
2
. . . S8
where
D = conductor sag (midspan) metres (m)
t = time (seconds) for N return waves
N = number of return waves (usually three)
g = gravitational acceleration—normally taken as 9.8067 metres per second squared
(m/s2)
This method should only be used where the design allows for reasonable sagging errors
and where the attachment points are relatively level. It assumes that the wave travels for a
distance equal to the span length rather than the true conductor length. No allowance has
been made for the attenuation of the wave velocity because of the flexural stiffness (EI) of
the conductor.
S11 SWING METHOD
Another 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
⎞
⎛
D=⎜
⎟
⎝ 1.7946N ⎠
2
. . . S9
where
D = conductor sag in metres (m)
t = time for conductor to swing N times from one side to the opposite side and back
(seconds)
N = number of swings timed
This method has limited practical value and should not be used for conductors. It may be
useful for a relative comparison of stay tensions.
COPYRIGHT
237
AS/NZS 7000:2016
S12 DYNAMOMETER METHOD
A dynamometer measures the axial tension and not the horizontal component of tension that
is used in the design. The horizontal components of conductor tension either side of a
running sheave are equal when the take-off angles on either side are equal. If the conductor
is anchored at ground level at the end of a pull, there will be a considerable difference in
the take-off angles at the last running sheave (see Figure S7).
H1
H2
2
1
V2
T
V1
Running
s h e ave
T
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
FIGURE S7 TENSIONS ACROSS A RUNNING SHEAVE
H = H 2 − H1 = T (cosθ1 − cosθ 2 )
. . . S10
V = V1 + V2 = T (sinθ1 + sin θ 2 )
where
T
= axial tension of conductor as measured with a dynamometer
H
= resultant horizontal load on the running sheave
H1, H2 = horizontal component of conductor tension
V
= resultant vertical load on the running sheave (from the weight span)
V1, V2 = vertical component of conductor tension
In an extreme case where θ1 = 90° and θ2 = 0° the running sheave (or crossarm) will
experience a full termination load and an equally large vertical load.
When sagging or tensioning conductors a dynamometer can be installed in series with the
conductor to directly read the tension. After marking the appropriate conductor length or
position, the dynamometer is then removed and the conductor fixed to the marked position.
Shunt dynamometers are also available for small conductor diameters and usually require a
calibration chart for each conductor size.
Dynamometers should not be used for sagging when there are significant tension losses
from beginning to end of the pull, that is when—
(a)
the conductor pull is long i.e. many running sheaves are used;
(b)
the conductor runs through major angles;
(c)
there are large weight spans on the running sheaves; or
(d)
the diameter of the running sheaves is small in comparison with the conductor
diameter.
Neither should they be used when—
(i)
they are not recently calibrated; or
(ii)
their capacity is much greater than the sagging tension (mechanical analogue
dynamometers typically have a resolution that is 1% of their rated capacity).
COPYRIGHT
AS/NZS 7000:2016
238
APPENDIX T
RISK BASED APPROACH TO EARTHING
(Informative)
T1 RISK PROCESS
The risk based approach is based on ENA EG-0, Power System Earthing Guide and the EEA
Guide to Power System Earthing Practice.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
A probabilistic risk analysis is a calculation of the probability and consequences of various
known and postulated accidents. Probabilistic risk analyses 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 analyses are used to determine
the probability of causing fatality to one or multiple individuals. The basis applied for a
safe earthing design is a low probability of electrocution.
The risk of electrocution needs to be compared with individual and societal risk limits. The
risk is then categorized as ‘Low’, ‘Intermediate’ or ‘High’. Mitigation needs to be applied
for ‘High’ risk categories. In the ‘Intermediate’ region, mitigation needs to be applied to
reduce the risk as low as reasonably practical, or achievable. This implies considering
mitigation options and balancing the cost against the benefit of reducing the risk of
electrocution.
Design of an earthing system based on a risk approach to human fatalities can be
accomplished by the process outlined in Figure 10.4 for the EG-0 approach and Figure T1
for the EEA approach 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 allowing protection to operate and interrupt the fault
current. Detailed design is necessary to ensure that all exposed conductive parts are
earthed. Extraneous conductive parts should be earthed, if appropriate. Any structural
earth electrodes associated with the installation should be bonded and form part of the
earthing system. 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 site, determine earth potential rise (EPR).
(e)
Determine the tolerable step and touch voltages from Section 10 standard curves.
(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 of the standard curves in Section 10. Note that
touch voltage limits can be conservatively applied to step voltages.
(h)
If not, assess the risk as summarized below—
(i)
estimate the frequency and typical duration of the fault events;
COPYRIGHT
239
(ii)
AS/NZS 7000:2016
estimate the extent of hazard areas or zones;
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
(iii) estimate the average length of time per visit 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). Classify the risk into 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 Paragraph T8.
(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 with mitigation measures, which can include separation of HV and LV
earthing systems.
(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 are fulfilled
and staff safety risk is effectively managed.
(q)
Review installation for physical and safety compliance following the commissioning
program.
(r)
Provide documentation including 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?
COPYRIGHT
AS/NZS 7000:2016
240
B asic d ata
Earth fault cu rrent, fault clearing time, so il resist ivity and
prob ability of ear th fault o ccur r ing
M inimum d esign to m eet fun ction al requirem ents
Determ ination of step and tou ch voltage limits
)
(refer Section 10
EPR
d step
and
Yes
tou ch voltage
limits?
No
Identify
the risk by identifying all hazard s and extent of hazard areas. This is
Lightning and tran sient
design con sideration s
achieved by comparin g vo ltage limits (derived in Section 10)
with calculated o r measured voltages for all hazard s
Construction sup p or t
Estimate peop le expo sure to the h azard s.
Carr y ou t sensitivity analys is wh ere
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
required.
Com mis sioning
pro gram and safet y
Assess the risk associated with a structure or group of
comp lian ce revie w
structures where appropriate.
Assess according to risk matrix.
Risk outcome
High
Do cum en tation
Intermediate
Low
Carr y out C ost
De sign comp lete
Benefit A nalysis
Is r isk redu ction
impractical and
Yes
costs gro ssly
d ispropo rtionate to
safet y gained?
No
Ch eck transferred potentials
Mitigate hazard s.
Ch eck inter co nn ectio n of H V
and LV ear th ing systems
Ch eck circulating currents
No
Ar e all
ha zard s
Risk generally
mitigated?
acceptab le
(see NOT E )
Yes
NOTE: For low risk category, the risk is generally acceptable. However, risk treatment should be applied if the cost of
the risk treatment is low. A cost-benefit analysis may be required to assess the cost of the risk treatment.
FIGURE T1 EARTHING SYSTEM DESIGN FLOW CHART
COPYRIGHT
241
AS/NZS 7000:2016
T2 PROBABILITY CALCULATION
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.
In certain situations, hazards separated by short intervals derived from a single cause may
be approximated as a single fault.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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
probability of an individual being in a hazard zone during a fault can be described by Pc:
Pc = λH × λ E × ( LE + LH )
1
365 × 24 × 60 × 60
. . . T1
where
λH = hazard rate factor (average number of faults per year)
λE = exposure rate factor (average number of exposures per year)
LH = average hazard duration (in seconds)
LE = average exposure duration (in seconds)
Pc 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.
The probability that the heart will enter ventricular fibrillation due to contact with an
external voltage is the Probability of Fibrillation P(fib). A key purpose of earthing system
design is to minimize the likelihood of a fatality occurring P(fatality) (which can be described
by the following equation) to within societally acceptable low limits.
Pfatality = Pc × Pfib
. . . T2
AS/NZS 60479.1 can be used to determine the probability of fibrillation. However, this is
not straightforward. For conservative design the probability of fibrillation can be set to one.
Hence, Pc can be used as a conservative measure of the probability of electrocution.
For New Zealand, since the touch and step voltage limits are based on AS/NZS 60479.1
curve C2, Pfib is considered to be 1 when the touch or step voltages exceed the touch or step
voltage limits. Pfib is considered to be 0 when the touch or step voltages are below the touch
or step voltage limits.
In some cases it may be more useful to set the coincidence probability, Pc, to the high and
low limits for individual risk of electrocution, Phigh = 10−4, Plow = 10−6 and back calculate
the limits for the number of visits to the hazard zone each year.
COPYRIGHT
AS/NZS 7000:2016
242
μl ow−int =
μint-high =
31 536 000 ×1×10−6
λH
31 536 000 × 1 × 10−4
λH
×
LE
LE
31.5
=
×
LE + LH
λH LE + LH
. . . T3
×
LE
LE
3153.6
=
×
LE + LH
LE + LH
λH
. . . T4
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 = λELE
. . . T5
where
λE = exposure rate factor (average number of exposures per year)
LE = average exposure duration (in seconds)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
T3 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 T1 and
Table T2, respectively. For considering faults on overhead lines, if the line 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.
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, LH, can be estimated from values given in
Table T2. Note that for faults close to a substation, earth fault current 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.
COPYRIGHT
243
AS/NZS 7000:2016
TABLE T1
TYPICAL OVERHEAD LINE FAULT RATES
System voltage
(phase-to-phase)
Overhead line fault rate
(faults/100 km year)
LV
20–150
11 kV–33 kV
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
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTES:
1
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.
2
The higher outage rates occur in northern Australia where
there is more frequent high wind and lightning storms.
3
The lower outage rates occur in southern Australia and New
Zealand where there is less frequent high wind and lower
lightning activity.
TABLE T2
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: The primary protection clearing times for line
voltages >100 kV are based on National Electricity
Code fault clearing time requirements for remote end.
COPYRIGHT
AS/NZS 7000:2016
244
T4 SIMPLIFIED CALCULATION OF PERMISSIBLE EXPOSURE LIMITS
The probability calculation of Paragraph T2 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.
Further analysis is required where this does not apply such as where a significant seasonal
effect needs to be accommodated however, the more complex formula does not usually alter
the calculated probability significantly. If conditions (a), (b), and (c) are met, the range of
limits for cumulative exposure per year can alternatively be calculated as—
μhigh =
3153.6
λHigh
, μlow =
31.536
. . . T6
λHigh
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The coincidence probability may be calculated using the simplified equation—
Pc = λH × λE × LE
1
365 × 24 × 60 × 60
. . . T7
Example 1:
Problem:
A jogger goes for a run every day of the week. At the end of each run, the jogger leans
against an 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 LE is 120 s, and
the average number of exposures per year, λ E, is 365. Faults occur once every 150 years on
average. The fault rate factor is therefore—
λH =
1 hazard
= 6.67 × 10−3 hazards per year
150 years
. . . T8
The equivalent probability is therefore—
Pc ≈ λH × λE × LE
1
6.67 ×10−3 × 365 × 120
=
= 9.3×10−6
365 × 24 × 60 × 60
365 × 24 × 60 × 60
. . . T9
This risk level is above the tolerable level of 10 −6 and falls in the Intermediate risk category
defined in Paragraph T7. Consequently, risk treatment measures should be investigated to
reduce the risk to as low as reasonably practical.
Solution 2:
The hazard rate λ H is equal to—
λH =
1 hazard
= 6.67 × 10−3 hazards per year
150 years
COPYRIGHT
. . . T10
245
AS/NZS 7000:2016
The limits for the cumulative exposure per year are—
μhigh =
3153.6
λH
=
3153.6
= 472 803 per year = 9092 s per week
6.67 × 10−3
μlow = 0.01 × μlhigh = 4728 s per year = 91 s per week
. . . T11
. . . T12
The jogger’s exposure is above the lower limit of 91 s per week and falls in the
‘Intermediate’ risk category defined in Section 10. As expected, the methods used in
Solution 1 and Solution 2 produce the same result.
T5 ADVANCED CALCULATION OF THE PROBABILITY OF FATALITY
If a situation does not meet one or all of conditions (a) to (c) in Paragraph T4, 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
T6 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 account 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 a duration of 1 s.
Solution:
The risk associated with this scenario may be calculated directly using Equation T1 as
shown. The average length of an exposure LE is approximately 1 s, the average length of a
fault LH is 1 s, and the number of exposures per year that occur λ E is 365. The rate at which
hazards occur is—
λH =
1 hazard
= 8.33 × 10−3 hazards per year
120 years
. . . T13
The coincidence probability per year is therefore—
Pc = λH λE ( 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
COPYRIGHT
. . . T14
AS/NZS 7000:2016
246
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 T7. Consequently, no risk treatment
action is necessary.
Solution 2:
The fault rate factor is therefore—
λH =
1 hazard
= 8.33 × 10−3 hazards per year
120 years
. . . T15
The limits for the cumulative exposure per year are—
μhigh =
3153.6 ⎛ LE
λH ⎜⎝ LH + LE
⎞
3153.6 ⎛ 1s ⎞
⎟=
⎟ = 189 291 s per year
−3 ⎜
×
+
8.33
10
1s
1s
⎝
⎠
⎠
. . . T16
= 3640 s per week
μlow = 0.01 × μlhigh = 1893 s per year = 36 s per week
. . . T17
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The exposure of an individual in the hazard zone can be calculated by using—
μ = λ E LE = (1) = 365 s per year = 7 s per week
. . . T18
The jogger’s exposure is below the lower limit of 36 s per week and falls in the ‘Low’ risk
category defined in Section 10. As expected, the methods used in Solution 1 and Solution 2
produce the same result.
T7 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. A key purpose of earthing system design is to
minimize the likelihood of a fatality occurring to within societally acceptable low limits.
The societally acceptable limits are based upon meeting both individual limits, and societal
(also known as group or multiple) risk limits. In situations where a number of persons
gather or congregate around the asset (such as poles near meeting places), societal risk
limits predominate. In other cases where few individuals come in contact with the asset,
individual limits dictate.
Individual limits
The unacceptable and acceptable individual fatality probability limits in the context of this
document are shown in Table T3.
COPYRIGHT
247
AS/NZS 7000:2016
TABLE T3
Probability of single
fatality
(per year)
Risk classification
for public death
≥10 −4
High
Intolerable.
Needs to prevent occurrence regardless of
costs.
10 −4 –10 −6
Intermediate
As low as reasonably practical for
intermediate risk.
Needs to minimize occurrence unless risk
reduction is impractical and costs are
grossly disproportionate to safety gained
≤10 −6
Low
Resulting implication for
risk treatment
As low as reasonably practical for low risk.
Minimize occurrence if reasonably practical
and cost of reduction is proportionate to the
reduction in risk
Societal limits (EG-0 approach only)
To determine the compliance of a situation involving a societal presence profile, it is
necessary to calculate the societal probability of coincidence associated with multiple
fatalities associated with average exposure characteristics. This is combined with the
probability of fibrillation for the design scenario to determine the societal probability of
fatality and the results can be laid over the target F-N curve (see Figure T2).
As a demonstration, for a particular situation involving an exposed population of
100 people (i.e. number of people that could be reasonably expected to come in contact at
one time), the results in Table T4 for societal coincidence were obtained:
TABLE T4
SOCIETAL (MULTIPLE FATALITY) F-N RISK CURVE
CONSTRUCTION EXAMPLE
Number of people
(N)
Probability that N will be
coincident with a fault
Probability that >N will be
coincident with a fault
2
3
4
9.93 × 10 −5
1.04 × 10 −6
8.02 × 10 −9
3.67 × 10 −5
3.83 × 10 −7
2.97 × 10 −9
For a calculated probability of fibrillation of 0.37 (based upon an applied voltage, fault
duration, and series resistance), the curve shown in Figure T2 is obtained:
FR EQ U EN CY O F N O R M O R E
FATA LI T IES, F
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
RISK MANAGEMENT MATRIX—FREQUENCY OF OCCURRENCE
VERSUS SEVERITY OF CONSEQUENCE
1e - 4
Into l e r a b l e
1e - 5
AL ARA Region
1e - 6
1 e -7
1e - 8
Negligible
1e - 9
2
10
N U M B ER O F FATA L I T I ES , N
FIGURE T2 F-N SOCIETAL RISK CURVE EXAMPLE
COPYRIGHT
10 0
AS/NZS 7000:2016
248
Because some of the curve shown in Figure T2 example exists in the ALARA (i.e. as low as
reasonably achievable) region, ALARA principles are to be used to reduce the risk profile.
If the calculated fatality probability lies within the ALARA region, it is necessary to
consider mitigation in the design.
The ‘by-hand’ approach does not allow for calculation of multiple fatalities (i.e. societal
risk assessment). However, this is not a major limitation as the societal fatality scenario is
usually only the critical case for locations where many people congregate regularly. For
these cases Section 10 gives some limits.
T8 RISK TREATMENT MEASURES
T8.1 General
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
These methods are detailed below.
T8.2 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 needs to 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 circumstances, the increase in the size of the EPR contours may
be significant for a small reduction in the EPR of the system. 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.
COPYRIGHT
249
AS/NZS 7000:2016
T8.3 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.
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 EPR events at the
conductive poles or towers will become more frequent since each 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 should be given to the shield wire size (fault rating), particularly for the first
few spans from the substation.
T8.4 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.
T8.5 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.
COPYRIGHT
AS/NZS 7000:2016
250
T8.6 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.
NERs may be an effective way of reducing the EPR at faulted 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 can reduce MEN EPR to a safe level even in systems with high
MEN resistance.
T8.7 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.
T8.8 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 resistance to touch and step voltage circuits.
COPYRIGHT
251
AS/NZS 7000:2016
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 vehicle
access. Vehicle access over crushed rock may sometime be problematic especially if the
basecourse is not prepared correctly.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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. Recent testing indicates that the above flashover
withstand voltages may be conservative and could typically be as high as 20 kV for
properly compacted asphalt.
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 minimum thickness of 50 mm should be used 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 should be
maintained.
Close attention is required to the preparation of the ground prior to the application of
crushed rock or asphalt. Suitable basecourse should 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.
T8.9 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.
COPYRIGHT
AS/NZS 7000:2016
252
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.
T8.10 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The minimum separation distance required between the HV and LV earthing systems is
dependent on—
(a)
the size of the HV earthing system;
(b)
the maximum EPR on the HV earthing system; and
(c)
the distances to the earths bonded to the LV system.
A minimum separation distance 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 separate poles; or
(C)
LV aerial bundled conductor cable that is insulated to withstand the full HV
conductor voltage.
The transformer should 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, should 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.
T8.11 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
non-conductive 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.
COPYRIGHT
253
AS/NZS 7000:2016
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 case study involves an existing 33 kV concrete pole located on an urban footpath. This
pole was identified as potentially carrying an EPR risk for people passing by. It is assumed
that footwear is worn around the pole.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Step 1—Basic data:
(a)
The prospective earth fault current at the source substation is 7 kA.
(b)
The resistance to earth of the 33 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 five 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(a)—Prospective tolerable step and touch voltage limits (EG-0)
The touch voltage limit was determined from Figure 10.1 curve DU for a fault clearing time
of 0.5 s and for a soil resistivity of 50 Ω-m (footwear included).
VT (limit) = 4000
EG-0 does not provide standard curves for step voltage limit as touch voltage is generally
the governing condition. Step voltage for Australian EG-0 method will not be considered
further in the example.
Step 5(b)—Prospective tolerable step and touch voltage limits (EEA/NZ)
The touch voltage limit is determined from Figure 10.6 Touch voltage limits for normal
locations including 2 000 Ω shoes for a fault clearing time of 0.5 s and for a soil resistivity
of 50 Ω-m (footwear included).
The step voltage limit is determined from Figure 10.5B, Step voltage limits for special
locations excluding shoe resistance for a fault clearing time of 0.5 s and for a soil
resistivity of 50 Ω m (footwear excluded).
VT (limit) = 400 V
VS (limit) = 200 V
COPYRIGHT
AS/NZS 7000:2016
254
Step 6—Is EPR ≤VT (limit)?
The EPR on the pole is greater than the touch and step voltage limits.
Step 7—Calculate actual touch voltages
The actual touch voltage on the pole was calculated as approximately 4500 V.
The actual maximum step voltage was calculated as approximately 1500 V.
Step 8(a)—Are actual touch and step voltages ≤VT (limit)? (Australia)
Actual touch voltage exceeds the touch voltage limit.
Step 8(b)—Are actual touch and step voltages ≤VT (limit) and VS (limit)? (New
Zealand)
Actual touch voltage and step voltage both exceed the limits. Therefore, step and touch
voltage hazards exist.
Step 9—Risk analysis
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
There are hazardous step and touch voltages on the concrete pole. The risk can be assessed
by calculating the coincidence probability.
Applying Equation T7
Pc = λH × λE × LE
1
365 × 24 × 60 × 60
The frequency of earth faults for the line with 200 poles is 5 faults per year. Therefore—
λH =
5
= 0.025
200
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 year), λ E = 260.
LE = 5 min × 60 s = 300 s
Pc = λH × λE × LE
1
(0.025)(260)(300)
=
= 6 ×10−5
365 × 24 × 60 × 60 (365 × 24 × 60 × 60)
Assuming the probability of fibrillation is one, the equivalent electrocution probability is—
Pe = Pc = 6 × 10−5
Since only one person is typically affected, N2 = 1 and the equivalent probability is—
Pe = N2 × Pc = Pc = 6 × 10 −5
The risk is therefore ‘Intermediate’ and should be minimized 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%)
COPYRIGHT
255
AS/NZS 7000:2016
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)
Installing a neutral earth impedance to limit fault current.
A few of the above risk treatment options are detailed below to illustrate the principles.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
(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 options has
been determined to be approximately $200 k. Comparing the cost of risk 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
EG-0
With a gradient control conductor installed at a distance of one metre around the pole,
the touch voltage reduces to 900 V. This touch voltage is below the touch voltage
limit. Alternatively, if asphalt is installed around the pole, the touch voltage is lower
than the limit. The cost for either of these risk treatment options is $10 k and is below
the present value of the liability. There may be some additional ongoing costs
associated with maintenance of the asphalt.
EEA/NZ
With a gradient control conductor installed at a distance of one metre around the pole,
the touch voltage reduces to 900 V. This touch voltage exceeds the touch voltage
limit. However, if asphalt is also installed around the pole, the touch voltage limit
increases to 1500 V with the result that the touch voltage is lower than the limit. The
cost of this risk treatment option is $12 k and is below the present value of the
liability. There may be some additional ongoing costs associated with maintenance of
the asphalt.
(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. However, there may be difficulty
in maintaining the insulation integrity of the barrier for the life of the line. There may
be some additional ongoing costs associated with maintenance of the insulating
barrier.
(iv)
Additional risk treatment options may be considered as required
Clearly, economically viable risk treatment options exist for this case and one of the
options should be implemented. The cheapest risk treatment option may not be the
best option. Other considerations may dictate which risk treatment option is selected.
COPYRIGHT
AS/NZS 7000:2016
256
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 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 min per week for the risk to
become ‘High’. In this case, it is unlikely that someone would be exposed for so long every
week.
μhigh
3153.6
λh
= 126 144 s per year = 2426 s per week
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
μlow =
31.5
λh
= 1260 s per year = 24 s per week
The above sensitivity check confirms that an intermediate risk level should be adopted for
this case.
COPYRIGHT
257
AS/NZS 7000:2016
APPENDIX U
CONDUCTOR PERMANENT ELONGATION (CREEP)
(Informative)
Conductor metallurgical creep expressed as a function of time, temperature, conductor
stress and conductor constants is given as—
ε = α t β σ γ e δ(θ−20)
. . . U1
where
ε = unit strain (mm.km−1 or μS)
t = time (years)
σ = average conductor stress in Megapascals (MPa)
α , β , γ and δ are constants
If the average temperature over the life of the conductor is assessed to be 20°C the above
equation may be reduced to—
ε = α t βσ γ
. . . U2
Conductor constants are determined by conductor creep tests as described in AS 3822.
Typical creep test results are illustrated in Figure U1 and yield the creep constants
α , β , γ and δ .
LO G ( ELO NG AT IO IN )
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
θ = average conductor temperature (°C)
T85C = 20 % C B L
T20C = 40 % C B L
T20C = 3 0 % C B L
T20C = 20 % C B L
I n i ti a l c re e p
LO G ( T IM E )
FIGURE U1 TYPICAL CONDUCTOR CREEP TEST RESULTS
In reality, the conductor never experiences constant stress and constant temperature over its
lifetime. Therefore the cumulative conductor creep is dependent on the aggregation of creep
intervals characterized by differing conductor stresses and temperatures. A conductor may
be subjected to a number of differing stress levels and temperatures each with a given time
interval as illustrated in Figure U2. In this example, the initial exposure is at 20% CBL and
20°C with a duration, t1 to t2 which will result in creep accumulation of ε2 − ε1 as the
conductor behaviour moves from a to b.
COPYRIGHT
258
l o g (e l o n g a ti o n)
AS/NZS 7000:2016
d
e
b
c
a
t3
t1
t4
t2
t5
l o g (ti m e)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
FIGURE U2 TYPICAL CONDUCTOR CREEP ACCUMULATION
At c, the conductor experiences an elevated temperature at say 16% CBL and 85°C with
duration, t3 to t4, 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 creep may be determined from 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;
(b)
the creep from one creep curve may be translated to another creep curve (i.e. from
point b to point c and also from point d to point e); and
(c)
the creep is cumulative.
Conductor creep is cumulative for a given set of operating conditions of time, temperature
and stress.
γ
⎛ σ ⎞β
ti = ti −1 ⎜⎜ i −1 ⎟⎟ e δ ( θ i −1 − θ i )
⎝ σi ⎠
. . . U3
where
ti
= the equivalent time for strain at stress level σi (years)
ti−1 = time interval associated with stress level σi−1 (years)
σi = the stress level associated with time interval ti Megapascals (MPa)
σi−1= the stress level associated with time interval ti−1 Megapascals (MPa)
Reference: CIGRE WG 22.05 ‘Permanent Elongation of Conductors Predictor Equations
and Evaluation Methods,’ CIGRE Electra No 75 1981.
COPYRIGHT
259
AS/NZS 7000:2016
APPENDIX V
CONDUCTOR MODULUS OF ELASTICITY
(Normative)
V1 GENERAL
Typical homogeneous conductor modulus of elasticity is given as—
Eal = 64 GPa (aluminium)
. . . V1
Est = 193 GPa (SC/GZ)
. . . V2
N O R M A LI Z E D S T R E S S
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Figure V1 illustrates a stress strain curve for a homogenous conductor being loaded and
unloaded. As the applied load exceeds the elastic limit of the conductor, some permanent
elongation will result as shown in Figure V1.
Unloading
Loading
S T R A I N (% E LO N G AT I O N )
FIGURE V1 STRESS STRAIN CURVE FOR A HOMOGENOUS CONDUCTOR
Figure V2 illustrates a stress strain curve for a non-homogenous conductor such as an
ACSR construction.
COPYRIGHT
AS/NZS 7000:2016
260
N O R M A LI Z E D S T R E S S
C o m p o s i te c o n d u c to r
O u te r wi r e s (a l )
C o r e (gz)
Tr a n s i ti o n p o i n t
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
S T R A I N (% E LO N G AT I O N )
FIGURE V2 STRESS STRAIN CURVE FOR NON-HOMOGENOUS CONDUCTOR
The initial characteristics of the conductor stress strain may be described by a polynomial
equation as follows:
ε = A0 + A1 σ + A2 σ2 + A3 σ3 +…...+An σn
. . . V3
where
ε = conductor strain
An = coefficients derived from conductor testing
σ = conductor stress
‘A0’ is generally very small and can be ignored. Usually a third order polynomial describes
the data adequately, however in some cases higher orders may be more appropriate.
However, the order of the polynomial (n) can be no more than the number of data points
less one. Similar polynomials are derived for the initial curves of the steel core and the
aluminium outer layer. Linear regression may be applied to the unloading curves to
determine 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 using—
Ecomp =
A1E1 + A2 E2
A1 + A2
. . . V4
where
A1, A2 = cross-sectional area of the core and outer strands
E1, E2 = modulus of elasticity of the core and outer strands
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 steel wires.
Equation V4 does not account for the wire geometry of a helical stranded conductor and
this equation will always overestimate the modulus by about 1%. A 1% error in modulus
will generally result in conductor sag error of about 2%.
COPYRIGHT
261
AS/NZS 7000:2016
By examining the wire geometry of a helically stranded wire, Nigol and Barrett [1] derived
an equation for the conductor strain related to the wire strain, and to the change of layer
radius. From this work, a more accurate modulus may be determined and for a
non-homogenous conductor with multiple layers the composite modulus is detailed in the
relevant Australian conductor Standard.
The moduli 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 point
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 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Of particular interest is the change in transition point with a change in temperature. A
phenomenon reported by Nigol and Barrett [1] known as the birdcaging temperature, above
which 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 V1.
TABLE V1
CONDUCTOR TENSION DETERMINATION MODELS
Model
Modulus of elasticity
Non-linear stress strain
The stress strain curve is described by a polynomial equation so
that permanent elongation is included for tension excursions
Linear stress strain
Use final modulus for both homogeneous or non-homogeneous
conductors
V2 REFERENCE
[1]
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.
COPYRIGHT
AS/NZS 7000:2016
262
APPENDIX W
CONDUCTOR COEFFICENT OF THERMAL EXPANSION
(Informative)
Homogeneous conductor coefficient of thermal expansion (CTE) is given as—
αal = 23 × 10−6 (aluminium)
αst = 11.5 × 10−6 (sc/gz)
Non-homogenous conductor, consisting of dissimilar materials, the composite CTE above
the transition point is given as—
αcomp =
A1E1α1 + A2 E2α 2
A1E1 + A2 E2
. . . W1
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
where
A1, A2 = cross-sectional area of material 1 and 2
α1, α2 = coefficient of thermal expansion of material 1 and 2
E1, E2 = modulus of elasticity of material 1 and 2
Below the transition point, the CTE will be that of the core material and in the case of an
ACSR, the CTE will be that of the steel wires.
Equation W1 does not account for the wire geometry of a helical stranded conductor and
this equation will always overestimate the CTE by up to 5%. A 5% error in CTE will
generally result in conductor sag error of about 2%.
COPYRIGHT
263
AS/NZS 7000:2016
APPENDIX X
CONDUCTOR DEGRADATION AND SELECTION FOR DIFFERING
ENVIRONMENTS
(Informative)
X1 GENERAL
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 conductor 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 duration of wetness is a principal factor.
X2 CORROSION MECHANISMS
X2.1 Pit corrosion
Pitting is the loss of parent material at a localized site on a surface exposed to the
environment. Pitting may be caused by corona corrosion in UHV lines or more commonly
by localized electrolytic reaction in which water and oxygen need to 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 localized corrosion is not likely to occur and the overall effect
would be the gradual loss of cross-sectional area.
X2.2 Crevice corrosion
When an electrolyte such as water is present in the interstitial spaces between wires,
localized 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 perhaps in close proximity to chloride and or sulphate atmospheric depositions.
Corrosion is evidenced by voluminous grey to white slightly moist deposits between the
penultimate and ultimate aluminium layers. Chemical investigations generally reveal levels
of aluminium oxide, sulphates and chlorides of about 60%, 5% and 1% respectively.
X2.3 Homogenous Al and Al alloy conductors
The corrosion mechanism is generally limited to pit corrosion and is influenced 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 alloy. One example is aluminium alloy 6201
that employs compound Mg2Si, is anodic in aluminium and reactive to acidic solutions and
tends to dissolve away leaving an inactive pit.
COPYRIGHT
AS/NZS 7000:2016
264
X2.4 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 near 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.
X2.5 Homogenous galvanized steel wire conductors
The corrosion mechanism is initially limited to 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 reliable correlation in determining the expected life of zinc coated wires.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 X1.
TABLE X1
CORROSION RATES FOR ZINC AND STEEL
Corrosivity
classification
Corrosion rate
μm/yr−1
Zinc/steel corrosion
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
4 >10
80–200
1:20
Severe marine (<1 km)
X2.6 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.
X3 PROTECTIVE GREASES
Protective greases provide a layer or barrier to corrosion products and conductors may be
partly greased which provides better performance than ungreased conductors do. 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 the line.
COPYRIGHT
265
AS/NZS 7000:2016
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 66 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 70°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.
X4 APPLICATION RECOMMENDATIONS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Carter [Ref. 2] 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 three 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 three years and complete removal of the
zinc coating will occur in 3 years with salt deposition > 160 g.m −2.
(f)
A delay in the onset of internal corrosion results will occur from the use of protective
grease.
When selecting 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 completely 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.
Table X2 gives the conductor selections for differing environmental conditions.
COPYRIGHT
AS/NZS 7000:2016
266
TABLE X2
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
CONDUCTOR SELECTION FOR DIFFERING ENVIRONMENTS
Salt spray pollution
Industrial pollution
Conductor
type
Open ocean
Bays, 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
X5 REFERENCES
1
ROBINSON, J., Development of A Durability Branding System for Steel Construction
Products, Corrosion Management, Vol 10, No. 2, November 2001, pp 3–10.
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 Assessment of Serviceability of Aged
Transmission Line Conductors, Postgraduate Thesis, Wollongong University, 1989.
COPYRIGHT
267
AS/NZS 7000:2016
APPENDIX Y
CONDUCTOR STRESS AND FATIGUE
(Informative)
Y1 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.
Y2 STATIC STRESSES
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Y2.1 Static tensile stress
The conductor tension produces static tensile stresses in the individual strands. 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 + nASt
. . . Y1
where
σAl = stress in aluminium wires
AAl = area of aluminium
ASt = area of steel
T
= conductor tension
n
= ESt/EA1
EAl = 68 GPa (aluminium)
ESt = 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 Y1 may be rewritten as—
σ A1 ∝
T
m
. . . Y2
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.
Y2.2 Static bending stress
Static bending stress results from the bending of the conductor at the support point and is a
function of the vertical take-off angle, deviation angle, tension, self-weight and flexural
stiffness of the conductor and the radius of curvature of the support clamp.
Y2.3 Static compressive stress
Static compressive stresses arise because of tensile and bending forces in the strands of the
conductor and the conductor’s self-weight on the support and from external clamping
pressures.
COPYRIGHT
AS/NZS 7000:2016
268
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.
Y3 DYNAMIC STRESSES
Dynamic stresses are alternating bending stresses caused by wind-induced vibration of the
conductor and the stresses can vary widely in magnitude, frequency and duration. The
fatigue fracture of a strand 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 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.
f =
185 V
d
. . . Y3
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
where
f
= forced excitation frequency in Hertz (Hz)
V
= laminar wind velocity normal to the conductor in metres per second (m/s)
d
= conductor diameter in millimetres (mm)
185 = Strouhal number which is an average value
The severity of the vibration problem is determined by—
(a)
the nature of the wind flow, i.e. its duration; its average speed and turbulence; its
direction with respect to the line;
(b)
self damping characteristics of the conductor;
(c)
conductor tension; and
(d)
application of external dampers.
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. Vibration is
induced by wind velocities between 0.5 m/s and 7 m/s. Wind velocities less than 0.5 m/s do
not have sufficient energy to induce vibration. Velocities greater than 7 m/s are generally
turbulent in nature and do not produce the vortex shedding necessary to induce vibration.
The temperature under which the horizontal tensions constraint is applied should be based
on the average temperature over the coldest month.
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 cracking and the overall endurance of the conductor is
significantly reduced.
COPYRIGHT
269
AS/NZS 7000:2016
Conductor fatigue endurance is related to bending and compressive static stresses and is
relatively insensitive to static tensile stress. However as static stress levels increase, the
conductor self-damping characteristics are reduced. Therefore the most significant factors
are—
(i)
tension (self-damping); and
(ii)
duration of exposure to laminar winds.
Y4 LIMITING OUTER LAYER STRESSES
Y4.1 Limiting static stresses
The outer layer stresses (OLS) used for the derivation of Table Y1 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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 tension.
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 tension.
In Table Y1, 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 Y1 are expressed as horizontal tension, rather than tangential tension.
This approximation is satisfactory, except for very long spans or for spans in very steep
terrain when tangential tension should be used. In addition, for spans between tension
structures Table Y1 Clamp Category C is applicable only. 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/suspension units. Because of appropriately designed
supports, a higher dynamic 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 with 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 in Table Y1 under ‘clamp
category’.
The performance of AAAC irrespective of alloy is considered to be related to fretting
fatigue and Table Y1 reflects this consideration.
Strand breakages due to Aeolian vibration have been reported in the penultimate layer
rather than the outer layer. This may be the consequence of allowing the conductor to twist
when tension stringing.
Standard cable is constructed with successive layers having opposite directions of lay to
minimize the torsional force in the cable, however it does not eliminate it. The calculation
of the moment is determined experimentally.
COPYRIGHT
AS/NZS 7000:2016
270
M=kTD
. . . Y4
where
M = residual moment of the cable restrained against twisting in Newton metres
(N.m)
k = experimentally determined torque factor
T = cable tension in Newtons (N)
D = nominal cable diameter in metres (m)
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The torque factor k is a characteristic feature of the particular cable construction and
usually ranges from 0 to 0.1. The value of k may also change with load.
A conductor that is free to rotate under load will always tend to twist until the net moment
is zero. If, for instance, the moment of the outer layer is predominant, the lay of the outer
strands will lengthen. At the same time the inner strands (laid in the opposite direction) will
shorten its lay length. The lengthening of the outer layer will reduce its moment, whereas
the simultaneous shortening of the inner strands will increase the stress and increase its
residual moment. Progressive twisting of the conductor will decrease the moment of the
outer layer and increase the moment of the inner strands until equilibrium is established.
The twisting of the conductor leads to a redistribution of forces and moments so that the
inner layers take an over-proportional share of the load. Consequently the conductor can
fail well below its rated strength. In a pull test where the conductor ends are free to rotate,
the over-proportionally loaded inner strands will break prematurely, perhaps only achieving
70% of its minimum breaking load.
Vibration damage may occur in the highly stressed inner layer, particularly in those places
where the strands cross over, and imposes additional stress. Any visual inspection of the
conductor is limited to the under-stressed outer strands.
An anti-twist device can be used when stringing conductor under tension to prevent it from
rotating. This technique is usually employed with OPGW to prevent alteration of the strain
free window of the optical fibres that are loose inside a tube or slot. The anti-twist device is
rigidly fixed to the leading end of the cable so that relative twisting between it and the cable
is prevented. A swivel may be used to connect the draw wire (rope) to the anti-twist device.
It is a more difficult procedure to terminate cable with large residual moments.
Consideration should be given to selecting conductor constructions with low torque factors
(k).
Y4.2 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 the following:
(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.
(d)
The use of self damping conductors.
(e)
The application of the horizontal tension in accordance with table Y1.
Combinations of open or rolling terrain without dampers are in general not recommended
because the level of dynamic stresses 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.
COPYRIGHT
271
AS/NZS 7000:2016
Y5 VIBRATION DAMPERS
Y5.1 General
Use of effective dampers is critical when higher horizontal tensions specified in Table Y1
are used. Selection of effective dampers should be based on the recommendations of the
manufacturer and compliance with the relevant Australian or New Zealand or equivalent
International Standards. The following considerations are relevant.
Y5.2 Damper type
Spiral dampers are generally considered more effective for conductor diameters up to
12 mm, and mass 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.
Y5.3 Damper construction
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Dampers should be constructed to a robust design to achieve a useful life compatible with
that of other line components and to avoid conductor damage at the point of attachment.
Consideration should be given to live line replacement, corona discharge and radio
frequency interference levels.
Y5.4 Damping characteristics (mass dampers only)
Y5.4.1 Frequency response and energy dissipation
Dampers should be capable of limiting bending stress and strain to permissible levels for all
frequencies of Aeolian vibration. Since the frequency is dependent on conductor diameter,
dampers with different responses will be required for different conductor sizes. It is
important that the dampers have adequate energy dissipation over the full spectrum.
Dampers which meet the performance criteria of AS 1154.1 will generally provide
acceptable performance.
Y5.4.2 Impedance
The reactive and resistive mechanical impedance of the damper should match the conductor
as closely as possible.
Z = Tm
. . . Y5
where
Z = resistive mechanical impedance of the conductor in kilograms per second (kg/s)
T = conductor tension in Newtons (N)
m = conductor mass density in kilograms per metre (kg/m)
Y5.4.3 Endurance
The fatigue life of the damper should be sufficient to endure the rigorous service life of the
conductor. The performance of the damper should have minimal deterioration due to fatigue
and ageing. Degradation due to exposure to ozone and ultraviolet light should be taken into
consideration with hardware that uses elastomer inserts or plastic spiral dampers.
Y5.4.4 Damper stress
The dampers should not create significant stresses on the conductor due to clamping or
damping reactive forces exerted by the damper clamp.
COPYRIGHT
AS/NZS 7000:2016
272
Y5.4.5 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. Dampers to be used in Category 1 Terrain
should provide substantially more energy dissipation than those used for higher terrain
categories. Likewise, longer spans require more energy dissipation. This may be achieved
by using more dampers or more efficient dampers.
Consideration should be given to damper life when selecting the number of dampers in a
span. There could be situations where effective energy dissipation can be achieved with
fewer dampers (based on energy balance considerations for mass dampers), but this may be
at the expense of the damper life.
Y5.4.6 Damper location
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The ideal location for a mass damper is at 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.
If external damping is required next to strain insulators, then two dampers should be used.
This is because of the obscure mechanical impedance of the termination and the difficulty
of locating a single damper at the ideal location for all forced excitation frequencies. If one
damper becomes a node then the other damper would ideally be located at the anti-node. If
the damper weights touch at this separation, then one damper should be inverted.
LL =
1
2f
T
m
. . .Y6
where
LL = loop length of standing wave in metres (m)
T = conductor tension in Newtons (N)
m = conductor mass density in kilograms per metre (kg/m)
f
= forced excitation frequency in Hertz (Hz)
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
TABLE Y1
CONDUCTOR EVERYDAY LOAD HORIZONTAL TENSION (H)
Conductor or overhead
earthwire type
COPPER
Base case
horizontal
tension
(% CBL)
25
Recommended incremental increase in horizontal tension
(% CBL)
Static stress considerations
Dynamic stress considerations
Damping/terrain category
Clamp category*
No dampers
Fully damped all
terrain categories
Terrain category†
A
B
C
1
2
0
1.5
2.5
0
2
Recommended
maximum
horizontal tension
(% CBL)
3
4
6.5
31
34
10
0
2.5
5.0
0
5
10
AAC
18
0
1.5
2.5
0
2
4
6.5
27
AAAC/1120
15
0
1.5
2.5
0
2
4
6.5
24
AAAC/6201
13
0
1.5
2.5
0
2
4
5.5
21
ACSR 3/4, 4/3
10
0
2.0
4.0
0
4
8
13.0
27
27
ACSR 6/1, 6/7
17
0
1.5
2.5
0
2
4
7.5
ACSR 30/7
16
0
1.5
2.5
0
2
4
6.5
25
ACSR 54/7, 54/19
18
0
1.5
2.5
0
2
4
6.5
27
23
AACSR/1120 6/1, 6/7
14
0
1.5
2.5
0
2
4
6.5
AACSR/1120 18/1
16
0
1.5
2.5
0
2
4
7.5
26
AACSR/1120 30/7
13
0
1.5
2.5
0
2
4
6.5
22
AACSR/1120 54/7, 54/19
14
0
1.5
2.5
0
2
4
6.5
23
AACSR/6201 6/1, 6/7
13
0
1.5
2.5
0
2
4
6.5
22
23
AACSR/6201 18/1
14
0
1.5
2.5
0
2
4
6.5
AACSR/6201 30/7
12
0
1.5
2.5
0
2
4
6.5
21
Optical conductor
14
NA
NA
2.0
NA
NA
NA
4.0
20
* Clamp category:
Short trunnion clamp, post or pin insulator with ties (without armour rods)
Type B
Post or pin insulator (clamped or tied) with armour rods or shaped trunnion clamps with armour rods
Type C
Helically formed armour grip with elastomer insert
Type 1
Flat, no obstacles (see Note 14)
Type 2
Rolling terrain with scattered trees (see Note 14)
Type 3
Mountain, forest or urban
AS/NZS 7000:2016
† Terrain Category:
Type A
273
COPYRIGHT
SC/GZ, SC/AC
16.0
AS/NZS 7000:2016
274
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTES TO TABLE Y1:
1
The wind condition under which the horizontal tension from Table Y1 is applied is based on low wind or a
laminar wind.
2
Generally, the temperature under which the horizontal tensions from Table Y1 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 maximum temperature and daily minimum temperature.
3
The load factor applied to the horizontal tension from Table Y1 is defined in Table 7.3 for serviceability
damage limit, F tw .
4
Limits for covered conductors are subject to further research.
5
Limits for LVABC are given in Table 4.1.
6
Limits for HVABC should be based on the limits for the messenger wire (subject to further research).
7
The tension values given in Table Y1 are a guide only and need not apply to situations where proven line
performance indicates that a higher or lower tension would be appropriate. This could apply for example
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.
8
When using the tension limits in Table Y1, additional considerations may need to be given to:
9
(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 taken to ensure that the damper efficiency range is effective over the range of
frequencies 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 endure vibration transmitted to them by
the conductor.
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 Y1 are normally used.
10 Any terminations, suspensions or joints should be designed so as not to cause damage to conductors or to
be damaged by conductors when the conductor is subject to vibration. Vibration dampers are designed 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.
11 For new conductor that is overtensioned, the tension limits of Table Y1 may be applied to the initial
stringing tension, especially if the sagging is carried out over the colder months. If the tension limits are
applied after creep (final) then extreme caution needs to be exercised when undamped conductor is in
sheaves prior to clamping in.
12 For new conductor that is pre-stressed, the tension limits of Table Y1 may be applied to the final (after
creep) tensions.
13 Tensions for optical conductors are based on a conductor composed of aluminium clad or galvanized steel
plus aluminium or aluminium alloy wires. The optical fibres are carried in a metallic tube located 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.
14 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.
15 Use of spacers on bundled conductors may contribute some damping but it is good practice to also fit
vibration dampers to bundled conductors. Spacers should be pseudo randomly located to avoid sub-span
oscillation.
COPYRIGHT
275
AS/NZS 7000:2016
APPENDIX Z
CONDUCTOR SHORT TIME AND SHORT-CIRCUIT RATING
(Informative)
Z1 FAULT RATINGS
Z1.1 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Z1.2 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 temperature coefficient of resistance is invariant;
(c)
the specific heat of the conductor is constant; and
(d)
the heating is adiabatic i.e. there is no heat loss from the conductor. (Assumed
because the fault duration is much less than the thermal time constant of the
conductor.)
⎡ Ar RJ 2t ⎤
⎥
DC ⎦
1 ⎡
1⎤ ⎢
T2 = 20 − + ⎢T1 − 20 + ⎥ e ⎣
Ar ⎣
Ar ⎦
where
T2
= final temperature in °C
T1
= initial temperature in °C
Ar
= temperature coefficient of resistance in °C–1
R
= resistivity in Ω.mm at 20°C
D
= density in g/mm 3 or kg/cm3
J
= current density in A/mm2
t
= duration in seconds (includes reclosure times)
C
⎧
⎡⎛ T + T ⎞
⎤
= specific heat = C20 ⎨1 + Ac ⎢⎜ 1 2 ⎟ − 20⎥
⎣⎝ 2 ⎠
⎦
⎩
C20 = specific heat at 20°C in J.g −1.°C−1
Ac
= temperature coefficient of specific heat
COPYRIGHT
. . . Z1
AS/NZS 7000:2016
276
Rearranging Equation Z1—
⎡
⎛ T + T2
⎞⎤ ⎡
DC20 ⎢1 + Ac ⎜ 1
− 20 ⎟ ⎥ ⎢ T2 − 20 +
⎝ 2
⎠⎦
⎣
1n ⎢
J 2t =
Ar R
⎢ T1 − 20 +
⎢⎣
1
Ar
1
Ar
⎤
⎥
⎥
⎥
⎥⎦
. . . Z2
TABLE Z1
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
CONDUCTOR CONSTANTS
Constants
Units
AAC
AAAC/
1120
AAAC/
6201A
HD
copper
SC/GZ
SC/AC
A r (at 20°C)*
°C −1
0.00403
0.00390
0.00360
0.00381
0.00440
0.00360
R (at 20°C)*
Ωmm
28.3 × 10 −6
29.3 × 10 −6
32.8 × 10 −6
17.77 × 10 −6
190 × 10 −6
85 × 10 −6
D*
g/mm 3
2.70 × 10 −3
2.70 × 10 −3
2.70 × 10 −3
8.89 × 10 −3
7.8 × 10 −3
6.59 × 10 −3
C 20 **
Jg −1 °C −1
0.9
0.9
0.9
0.4
0.5
0.5
A c **
°C −1
4.5 × 10 −4
4.5 × 10 −4
4.5 × 10 −4
2.9 × 10 −4
1.0 × 10 −4
1.0 × 10 −4
* 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—
*
— Morgan V T, Rating of Bare Overhead Conductors for Intermittent and Cyclic Currents, Proc IEE,
1361–1376, 116(8), 1969.
— Morgan V T, Rating of Conductors for Short-Duration Currents, Proc IEE, 555-570, 118(3/4), 1971.
— IEEE 738 Standard, Calculating the Current-Temperature relationship of Bare Overhead Conductors.
From Equation Z2 the fault rating can be determined based on maximum allowable
temperature. Constants for various conductor types are contained in the relevant Australian
Standards and as shown in Table Z1.
When dealing with ACSR conductors, neglecting the steel component and using only the
physical, electrical and thermal properties for aluminium will lead to a conservative current
density for the aluminium. For a more accurate analysis, See IEC 60865-1.
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 Z2 should not be exceeded.
COPYRIGHT
277
AS/NZS 7000:2016
TABLE Z2
GUIDELINES FOR 5% LOSS OF TENSILE STRENGTH FOR
TOTAL FAULT CLEARING TIME (INCLUDING RECLOSES)
Approximate size
(mm 2 )*
Maximum temperature
HDCu
60
200°C
AAC, AAAC/1120, ACSR/GZ,
100
160°C
300 to 500
150°C
100
220°C
Conductor type
ACSR/AZ,
ACSR/AC
AAAC/6201A
SC/GZ, SC/AC
400°C
OPGW
Dependent on construction
* 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Reference: ROEHMANN, L.F. and HAZAN, E., Short time annealing characteristics
of electrical conductors, AIEE Trans 82/3 p1061, Dec 1963.
Z1.3 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.
Z1.4 Movement of conductors under fault
The movement of conductors due to the electromagnetic forces generated by large currents
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-100-V3,
Research Project 260, 1978) Section A3, Simulation and Tests of Motion Due to Fault
Currents—gives equations which may be used to determine conductor swing 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.
COPYRIGHT
AS/NZS 7000:2016
278
APPENDIX AA
CONDUCTOR ANNEALING AND OPERATING TEMPERATURES
(Informative)
AA1 GENERAL
Aluminium alloys are designated by the numbering system in Table AA1. The first digit
specifies the principal 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
TABLE AA1
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 AA2.
TABLE AA2
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 stabilized 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.
COPYRIGHT
279
AS/NZS 7000:2016
AA2 WIRE FABRICATION
Aluminium strands are drawn from 9.5 mm rod, which can be produced either by 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 hot-rolled 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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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.
AA3 ANNEALING FROM ELEVATED TEMPERATURE OPERATION
Morgan [Ref. 6] proposed the formulae below for determining the loss of tensile strength of
strands due to annealing. Morgan relates 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.
B′
C′
⎛
⎛ R ⎞⎞
⎛
⎜ A′ + 1n( t ) + + D ′1n ⎜ ⎟ ⎟ ⎞
T*
T*
⎝ 80 ⎠ ⎠
⎝
−
e
⎟
W = Wa ⎜ 1 − e
⎜
⎟
⎝
⎠
. . . AA1
⎛ ⎛ D ⎞2 ⎞
R = 100 ⎜ 1 − ⎜ w ⎟ ⎟
⎜ ⎝ Do ⎠ ⎟
⎝
⎠
. . . AA2
where
W
= loss of tensile strength in the partially annealed state
(% of ultimate tensile strength in the tempered state)
Wa
= 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 (%)
Do
= diameter of wire prior to drawing (mm) – usually 9.5 mm for
aluminium
Dw
= diameter of the drawn wire i.e. strand diameter (mm) – usually
ranging from 2.5 to 4.75 mm for aluminium
Table AA3 is an excerpt from Table 2 of [Ref. 6] using average values of –C′/A′.
COPYRIGHT
AS/NZS 7000:2016
280
TABLE AA3
ANNEALING EQUATION CONSTANTS
Wa
(%)
A′
B′
(K)
C′
(K)
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
Alloy
D′
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.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AA4 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 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)
permanent attenuation losses for OPGW.
For AAC and AAAC earthwires, accelerated creep will accompany the reduction in tensile
strength. 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.
AA5 MAXIMUM OPERATING TEMPERATURES
The maximum operating temperature is a function of the acceptable level of permanent loss
of tensile strength (annealing) of the conductor. The loss of tensile strength results in
increased sag. It is appropriate to establish the maximum temperature at which a conductor
can operate while maintaining acceptable levels of degradation of tensile properties.
Typical conductor types and maximum operating temperature (Ref. 8) are given in
Table AA4. 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.
COPYRIGHT
281
AS/NZS 7000:2016
TABLE AA4
TYPICAL CONDUCTOR MAXIMUM TEMPERATURES
Conductor type
HDCu
AAC, AAAC/1120, AAAC/6201A
Operating maximum
temperature
≤100°C
Short circuit maximum
temperature
220°C
200°C
≤100°C or
≤120°C (see Note)
200°C
SC/GZ, SC/AC
—
400°C
OPGW
—
Dependent on
construction
ACSR/GZ, ACSR/AC, ACSR/AZ
NOTE: ACSR/GZ, ACSR/AC, ACSR/AZ operating at 120°C shall require the
application of a non-linear stress strain model to adequately design for any non-linear
behaviour of the conductor associated with the transition point (see Appendix W).
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Isothermal annealing curves are illustrated in Figures AA1, AA2 and AA3 for AAC 1350,
AAAC/1120 and AAAC/6201 respectively. These curves demonstrate the permanent loss of
tensile strength when a conductor operates at an elevated temperature.
The annealing characteristics of a conductor depend not only on temperature and time of
exposure but also on the diameter of the wires in the conductor. Typically, the loss of
strength curves shown in Figures AA1, AA2 and AA3 will comprise a range of values for a
given period, with the smallest wire size suffering the greatest loss in strength and the
largest size the least.
The temperature limit for normal operation of AAC, AAAC, and ACSR of 100°C results in
an approximate loss of strength of 3% of the original tensile strength after 1000 h operation
at this temperature. Figures AA1, AA2 and AA3 show that the heating period is not a major
factor until 100°C is exceeded.
For ratings for short time conditions, (e.g. when one circuit has to carry more than normal
current for a short time), both the maximum temperature and the duration of the emergency
load should be taken into account in determining the annealing of the aluminium wires. The
annealing effect is cumulative. For example, if a conductor is heated to 150°C under
emergency conditions for 24 h a year for 30 years, it is much the same as heating the
conductor continuously at that temperature for 720 h. For this example, the loss of ultimate
strength in AAC would be approximately 15%. For 30/7, ACSR the ultimate tensile strength
would be reduced approximately 7%. The effect is less significant for ACSR where an
increase in temperature results in a load transfer from the aluminium to the steel. The steel
provides a substantial proportion of the strength of the conductor and is essentially
unaffected by the normal operating and short time temperatures.
If ratings for emergency conditions are to be applied then the combined effects of elevated
temperature and sustained high sag of the line should be taken into account. Practically, the
tension in a line reduces with increasing temperature so the effect is less severe.
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
AS/NZS 7000:2016
282
FIGURE AA1 PERCENTAGE OF ORIGINAL TENSILE STRENGTH
FOR ALLOY 1350 vs AGEING TIME
FIGURE AA2 PERCENTAGE OF ORIGINAL TENSILE STRENGTH
FOR ALLOY 1120 vs AGEING TIME
COPYRIGHT
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
283
AS/NZS 7000:2016
FIGURE AA3 PERCENTAGE OF ORIGINAL TENSILE STRENGTH
FOR ALLOY 6201 vs AGEING TIME
AA6 REFERENCES
1
KIESSLING, F. et al, Overhead Power Lines – Planning and Design, Springer,
pp 250–251.
2
IEEE Std 1283—2004, IEEE Guide for Determining the Effects of High-Temperature
Operation on Conductors, Connectors, and Accessories.
3
BARBER, K.W. and CALLAGHAN, K.J., Improved overhead line conductors using
aluminium alloy 1120, IEEE Transactions on Power Delivery, Volume 10, Issue 1,
January 1995, pp 403–409.
4
WESTERLUND, R.W., Effects of composition and fabrication practice on resistance
to annealing and creep of aluminium conductor alloys, Metallurgical and Materials
Transactions B, Volume 5, Number 3/March, Springer Boston, 1974, pp 667–672.
5
CIGRE WG22.12, Loss in Strength of Overhead Electrical Conductors Caused by
Elevated Temperature Operation, ELECTRA No. 162, October 1995, pp 115–118.
6
MORGAN, V.T., Effect of Elevated Temperature Operation on the Tensile Strength
of Overhead Conductors, IEEE Transactions on Power Delivery, Vol. 11, No. 1,
January 1996, pp 345–352.
7
JAKL, F. and JAKL, A., 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, December 1963, p 1061.
COPYRIGHT
AS/NZS 7000:2016
284
APPENDIX BB
MECHANICAL DESIGN OF INSULATOR—LIMIT STATES
(Normative)
Table BB1 shows the load and wind conditions for a range of insulator types that shall be
considered in the design of insulators.
NOTE: The overhead line design handbook SA HB 331 provides worked examples.
TABLE BB1
INSULATOR LOADING CONDITIONS
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
State
Tension insulator
condition
Suspension and vee string
insulator condition
Post and pin insulator
condition
Everyday
—
Weight span, 0 Pa wind
Weight span, 0 Pa wind
Serviceable—working
wind (see Note)
—
Resultant load at serviceable
wind or 500 Pa transverse load
Resultant load with
serviceable wind or
500 Pa transverse
+ longitudinal unbalance
load
Serviceable—maintenance Construction and Resultant load for construction
maintenance loads and maintenance
Resultant load for
construction and
maintenance
Ultimate load
Resultant load with
ultimate transverse wind
+ longitudinal unbalance
load
Ultimate load
Resultant load for ultimate
conductor wind transverse load
or failure containment load
NOTE: The criteria for serviceable working wind is damage or deflection limit.
COPYRIGHT
285
AS/NZS 7000:2016
APPENDIX CC
EASEMENT WIDTH
(Informative)
Table CC1 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
depending on the line owner’s easement policy.
It is generally not required to obtain easements for overhead powerlines located on road
reserves because of building setback conditions contained in local authority planning
schemes.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
TABLE CC1
TYPICAL EASEMENT WIDTHS FOR A RANGE OF VOLTAGES
(FOR TYPICAL SPANS)
Easement building restriction widths
generally used (measured from the centre
line of the overhead line)
Typical width
of easement
m
m
Up to 33 kV
5 to 10
10 to 20
66 kV
10 to 15
20 to 30
110/132 kV
15 to 20
30 to 40
220 kV
15 to 25
30 to 50
275 kV conventional
25 to 30
50 to 60
275 kV guyed
30
70
330 kV
30
60
400 kV
30
65
500 kV
35
70
Nominal
voltage
COPYRIGHT
AS/NZS 7000:2016
286
APPENDIX DD
SNOW AND ICE LOADS
(Informative)
DD1 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 and/or 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 provided are considered to provide a reasonable guide to designers.
Only combined wind and ice loads on conductors are considered in this standard. Wind and
ice loads both combined and separate are considered in this Standard.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
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;
(b)
the mass or density of the ice layer; and
(c)
the shape of the ice layer (i.e. the diameter and the relevant drag factor).
Reference should also be made to the provisions contained in AS/NZS 1170.3 and CIGRE
TB 291. Paragraph DD2 makes specific provisions for Australia and Paragraph DD3 makes
specific provisions for New Zealand.
DD2 AUSTRALIA
In areas with ice and snow loadings, the minimum design loads should be based on a radial
thickness given in Table DD1 with a density of 900 kg/m 3 (SG = 0.9) and coincident with a
wind pressure of 100 Pa at a conductor temperature of −5°C. These loads may be taken as
corresponding to a return period of 50 years though the appropriateness is uncertain.
TABLE DD1
ASSUMED THICKNESS OF ICE IN AUSTRALIA
OTHER THAN TASMANIA
(Unless local climatic conditions, topography and line
directions are known to cause more severe loads)
Region
Radial thickness of ice (m)
Alpine
0.3d c
Sub-alpine
0.2d c
where
dc =
the diameter of the conductor
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 DD2 should be included in design
loadings.
COPYRIGHT
287
AS/NZS 7000:2016
TABLE DD2
TASMANIA REGION ICE LOADING CONDITIONS
Element
Elevation
(m)
Earthwire
0–499
Conductor
0–599
Ice condition—
900 kg/m3
Ambient
temperature
(°C)
Non-ice
Coexisting
temperature
Ice–6 mm
−10°C
Eathwire
500–799
Conductor
600–799
Earthwire and
conductor
800–999
Ice–9 mm
−10°C
>1000
Ice–12 mm
−10°C
>600
0 mm
—
Structures
(see Note 3)
Wind pressure
(Pa)
Spans >150 m
Spans <150 m
Inclement (design) weather
conditions prevail
360
720
360
720
720
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTES:
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 minimize
clashing of conductors. Earthwires are not to be positioned above phase conductors in
horizontal/flat construction configuration.
3
Ice build-up is assumed to occur only on conductors. Lattice structures with congested bracing
arrangements may trap snow. All gaps of less than 75 mm should be considered as additional
windage areas 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 should be 100 m lower at which ice conditions apply.
These effects may then be used to evaluate wire tensions and the calculation of wire loads
on structures.
DD3 NEW ZEALAND
DD3.1 General
For ice cases which include wind, the reduced return period wind should be applied to uniced 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, consideration should be made for the non-uniform ice build up
on adjacent spans on the support.
DD3.2 Line reliability load multiplier and security requirements
For snow and ice loadings, the return periods given in Table 6.1 are not appropriate as they
are relevant to wind loads only. Table 6.1 can be replaced with Table DD3 below which has
been developed specifically for snow and ice loads and uses a reliability load multiplier
instead of a specific return period.
This table is based on 50-year return period snow and ice loads as defined in
AS/NZS 1170.3.
The calculated snow and ice loads derived from Table DD4 should be then multiplied by an
appropriate reliability load multiplier as selected from Table DD3.
COPYRIGHT
AS/NZS 7000:2016
288
TABLE DD3
RELIABILITY MULTIPLIER FOR SNOW and ICE LOADS
Minimum reliability load multiplier M rel
Line security level
Design working life
Level I
Level II
Level III
0.30
0.50
0.65
<10 years
0.50
0.65
0.85
25 years
0.65
0.85
1.00
50 years
0.85
1.00
1.15
100 years
1.00
1.15
1.30
Temporary construction and
construction equipment, e.g. hurdles
and temporary line diversions with
design life of less than 6 months
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
NOTES:
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 adopted for
a particular structure or short sections of the line.
DD3.3 Temperature effects
Unless specific data is available, the following design temperatures should be used:
(a)
Snow—0ºC.
(b)
Ice:
(i)
Coastal areas: temperature = −0.0085 × altitude −3°C.
(ii)
Inland areas >5 km from coast: temperature = −0.0085 × altitude −5°C.
The temperature should be based on the highest altitude of the line. If there is significant
variation in altitude along the line, then the line should be broken into several temperature
zones. A lower temperature should be taken into account in regions where the temperature
often drops significantly after a snowfall.
DD3.4 Conductor tensions (Fts)
Consideration should be made for the overall effect of differences in tension of adjacent
spans on the structure.
Where significant span differences arise, the support should be checked for 70% of the full
loading on one side of the structure and 30% of loading on the other side.
All large deviation (greater than 30°) and termination supports should be designed for the
full ice accretion thickness on one side of the structure and no ice build up on the other
side.
Allowance should be made for some flexibility of post and pin insulators when calculating
tensions.
DD3.5 Snow and ice regions
The snow and ice regions are based on AS/NZS 1170.3 (snow regions) (see Figure DD1).
The regions are defined as follows:
(a)
Alpine Regions where the maximum snow load is usually due to accumulation from
a number of successive snowfalls.
COPYRIGHT
289
(b)
AS/NZS 7000:2016
Sub-alpine Regions where the maximum snow load is usually due to a single
snowfall.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Specific historical knowledge and records of other lines in the same locality may be utilized
in generating ice and snow loading requirements.
NOTE: This map is approximate only and altitude above mean sea level should be used to determine snow region. For
sub-alpine regions in the South Island (N2, N3, N4 and N5) the regions coincide with 1988 Council Boundaries.
FIGURE DD1 NEW ZEALAND SNOW AND ICE REGIONS
DD3.6 Radial snow and ice build-up on conductors
In the absence of site specific data, the snow and ice thicknesses for ultimate limit states
should be taken from Table DD4.
Table DD4 specifies radial snow/ice thicknesses corresponding to a 50-year event.
COPYRIGHT
AS/NZS 7000:2016
290
Relatively low density wet snow occurs down to low elevations below 600 m. At higher
elevations, ice is expected to form. Both snow and ice cases should be checked.
NOTE: Snow and ice actions may need to be considered in other areas where local records or
experience indicate that snow and/or ice accumulations occur.
TABLE DD4
SNOW AND ICE PARAMETERS FOR NEW ZEALAND
Radial snow or ice thickness (R ice ) on conductors
Region
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
N0
Upper North
Island
N1
Lower North
Island, and N2
West Coast of
South Island
N3 and N5
South Island
N4
Canterbury
Altitude
Wet snow
thickness at
400 kg/m 3
Ice thickness
(no wind) at
700 kg/m 3
Ice thickness
(with wind)
at 700 kg/m 3
Co-incident wind
return period for
ice (years)
450–600
25
—
—
–
600–900
30
5
2
1
900–1200
35
8
3
1
>1200
40
10
5
5
150–450
25
—
—
–
450–600
30
10
—
–
600–900
35
15
5
1
900–1200
40
20
8
5
>1200
45
25
10
5
0—150
30
10
—
–
150–300
35
15
—
–
300–450
40
20
—
–
450–600
45
25
—
–
600–750
—
30
—
–
750–900
—
35
5
5
900–1200
—
40
8
5
>1200
—
45
10
5
0—150
30
15
—
–
150–300
35
20
—
–
300–450
40
25
—
–
450–600
45
30
—
–
600–750
—
35
5
5
750–900
—
40
8
5
900–1200
—
45
10
5
NOTES:
1
The snow values are based on AS/NZS 4676 and Transpower radial thicknesses (converted to
uniform density values).
2
Where in-cloud icing may occur on elevated location expert guidance should be sought from local
meteorology sources.
DD3.7 Co-incident wind and ice conditions
No wind should be applied to wet snow.
Wind loads should be calculated as per AS/NZS 1170.2 for the specified return period in
Table DD3.
COPYRIGHT
291
AS/NZS 7000:2016
The drag coefficient to be used for wind co-incident with ice conditions should be taken as
1.1 times the relevant drag coefficient (Cd) for wind conditions only, but in no case be less
than 1.2.
Only winds from the SW, S or SE directions should be considered coincident with ice.
Wind forces coincident with ice should not be modified by span reduction multipliers
(SRF, TSRF).
DD3.8 Ice densities
For all radial ice thicknesses, a base density of 700 kg/m 3 should be used. This is consistent
with a medium rime ice, which is believed to be the predominant icing mechanism in New
Zealand. Use local information where available.
For conductors less than 11 mm diameter, the radial ice thickness should be increased by
10%.
DD3.9 Snow densities
For all radial snow thicknesses, a density of 400 kg/m 3 should be used.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
DD3.10 Differential ice loading for high security lines (Level III)
In addition to the uniform extreme ice/snow loading case, every structure within ice/snow
zones should also be checked for torsional and longitudinal loading resulting from
differential icing as described in the Table DD5 and Figure DD2. No coincident wind
should apply with differential icing.
x
a
b
c
y
a
(i) Single circuit
b
c
( ii ) S i n g l e c i r c u i t
x
a
b
a
c
d
e
b
d
e
f
c
( ii i ) D o u b l e c i r c u i t
f
( iv) D o u b l e c i r c u i t
FIGURE DD2 DIFFERENTIAL ICE LOADING
COPYRIGHT
AS/NZS 7000:2016
292
TABLE DD5
DIFFERENTIAL ICE AND SNOW LOADING CONDITIONS
Differential ice and snow loading conditions
Longitudinal condition
Torsional condition
Support type
Single circuit
Double circuit
Left span
Right span
Left span
Right span
(i)
abc
ABC
abC
ABC
(ii)
xyabc
XYABC
XYabC
XYABC
(iii)
abcdef
ABCDEF
abCdeF
ABCDEF
(iv)
xabcdef
XABCDEF
XabcDEF
XABCDEF
NOTES:
1
a,b,c,d,e,f, represent phase conductors and xy are earthwires.
2
ABCDEF, XY, represent spans loaded with 70% of maximum ice/snow weight.
3
The letters abcdef, xy, represent spans loaded with 30% maximum ice/snow weight.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
DD3.11 Snow loading on pole structures
Poles in areas subject to snow should have a minimum strength of at least 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.
Concrete poles in areas subject to snow loading should have flexibility of the pole or crossarm to allow for some equalization of out of balance loads and to limit cascade failures.
Consideration should be given to installing termination structures at regular spacings with
higher longitudinal strength or additional stays to support the structure.
Consideration should be given to the effects of redistribution of forces between stays and
rigid poles under snow loads.
COPYRIGHT
293
AS/NZS 7000:2016
APPENDIX EE
DETERMINATION OF STRUCTURE GEOMETRY
(Informative)
EE1 GENERAL
The tower/pole top geometry should be designed to ensure that adequate clearances exist
between live parts and the supporting structure under various conditions, and also to allow
safe climbing and safe live line work on the structure where required.
The geometry is determined by ensuring that minimum clearances are achieved for several
different operational scenarios. The worst case dimensions should be used.
Normal operation
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
The geometry should provide for both power frequency and lightning/switching impulse
clearances from live parts (conductors and fittings) to earthed metal and also conductor to
conductor.
Maintenance
The geometry should allow safe climbing (where the design requires it) of the structure.
This includes climbing past live conductors to access higher cross arms or the structure top.
Climbing is only allowed in low wind conditions typically less than 100 Pa. Therefore
insulator swing for 100 Pa wind needs to be taken into consideration.
Live line working (LLW)
Where live line working is to be used, the geometry should allow access to the working area
without infringing the live line working envelope. The safe working area should include any
specialist live line working equipment. LLW is only allowed under low wind conditions, so
insulator swing should again be considered at 100 Pa.
Figure EE1 shows a typical 132 kV suspension pole structure. The insulator swing angles
shown are typical for three design wind conditions. The actual swing angles should be
calculated as per Appendix Q.
Low wind is used to determine the LLW and maintenance approach distances (MAD).
Moderate wind is used to determine the serviceability clearances, which require
switching/lightning clearances to be achieved.
High wind is used to determine the electrical clearance, power frequency withstand level.
The criteria below indicate the points between which the clearances are to be achieved:
Cross-arm A
Live line maintenance 100 Pa low wind.
Maintenance approach 100 Pa low wind.
Criteria: The climbing corridor should not infringe the maintenance
approach distance-MAD [Figure EE1, Item (4)] from energized parts
(with auto reclose turned ON) in the low wind insulator swing
condition. The live line working corridor should not infringe the live
line working (AR OFF) [Figure EE1, Item (3)] clearance from the live
parts in the low wind swing condition.
COPYRIGHT
AS/NZS 7000:2016
294
Cross-arm B
Normal operation (serviceable) 300 Pa moderate wind.
Maximum electrical working (serviceable) 500 Pa high wind.
Criteria: Ability to withstand both switching and lightning impulse
voltages for moderate winds (300 Pa) and the power frequency
voltages for high winds (500 Pa). The clearances are from energized
parts to the earthed structure.
Cross-arm C
Climbing under 100 Pa low wind.
Criteria: The hand reach clearance should not infringe the power
frequency voltage withstand envelope surrounding the conductor.
Cross-arm A to B
Criteria: The distance from the live parts of the conductor/fittings on
cross-arm A to the top of any live line maintenance equipment on
cross-arm B should exceed the live line working (phase to earth)
clearances for the auto reclose system turned off.
All the above criteria should be satisfied for each cross-arm.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
In addition to these conditions, the following requirements may also affect the structure
geometry:
(a)
Maximum anticipated span length and clearances between conductors or earthwires,
or both at mid span (see Clause 3.7.3).
(b)
Maximum structure height and earthwire shielding to achieve desired lightning
reliability level (Note 10).
The dimensions in Figure EE1 are obtained or derived from the following:
1
Power frequency withstand for high wind from Table 3.4 of AS/NZS 7000.
2
Impulse withstand
AS/NZS 7000.
3
Live line working clearance from Table 9.1 of AS 5804.1 or NZECP46.
4
MAD for auto reclose is derived from NENS 04 (Australia), or EEA (NZ)
SM-EI—Part 3: Minimum Approach Distance (New Zealand).
5
Selected by the line owner based on equipment, work practices, climbing
equipment.
6
Selected by the line owner based on equipment, work practices, climbing
equipment.
7
See Figure 3.1 and the Note below.
8
Live line working clearance from Table 9.1 of AS 5804.1 or NZECP46.
9
Determined by live line equipment to be used.
10
Derived from lightning protection and reliability requirements (see Clause 3.4).
11
Determined by climbing provisions, for example ladder, step irons.
clearance
for
moderate
wind
from
Table 3.4
of
NOTE: The hand reach clearance extends from the climbing position to the power frequency
withstand envelope.
For a pole this is 1200 mm to the left and right of the climber, and 1700 mm to the rear of the
climber. The distance is measured from the face of the pole centrally between the climbing
aids or for the case of a ladder, the centre of the rungs.
For towers the hand reach dimension is measured from the face of the tower and is 1700 mm.
COPYRIGHT
295
AS/NZS 7000:2016
The shielding angle is determined by lightning simulation studies to achieve the desired
lightning performance.
10
Ear thwire shielding angle 40°
280 0
1910
110 0
Crossarm A
20 º low wind
swing 10 0Pa
9 fog t ype
insulator s = 1715
280 0
E x tent of
metal work
3
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
370 0
8
Live line
A /R of f 9 0 0
ine 0
el
0
Liv f f 9
o
R
A/
Crossarm C
M
ai
o a n te
na
12 ch
n
0 0 dis ce
m tan
ce
4 m
ap
pr
9
7
950
Hand reach
120 0
Crossarm B
Live line
maintenance
equipment
in extreme
position
50
1
50 0
0
20 º low wind
swing 10 0Pa
1
Power frequency
withstand
2
1300 switching and
lightning impulse
Pole centre line
35º moderate
wind swing 300Pa
70º high wind
swing 500Pa
6 1000 Square
climbing corridor
700 live line
working corridor
5
6
500
500
700 Live line
working corridor
R120 0
Climbing corridor
ELEVATION
11
6 10 0 0 S q u a r e
climbing
corridor
R1700
7
1000
Hand-reach
clearance
envelope
1000 Square
6 climbing
corridor
7
R1700
PL A N - L AT T I C E TOW E R
Hand-reach
clearance
envelope
PL A N - P O L E
FIGURE EE1 TOWER TOP GEOMETRY FOR 132 kV POLE
COPYRIGHT
AS/NZS 7000:2016
296
APPENDIX FF
STRUCTURAL TEST FOR PROTOTYPE POLES
(Normative)
FF1 SCOPE
This Appendix sets out methods for prototype testing of utility services poles in either the
horizontal or vertical position. Prototype poles include wood, concrete, steel and composite
material.
FF2 PRINCIPLE
Prototype poles are subjected to specified bending shear and, if required, torsional loads, to
establish their load-carrying capacity at the strength limit state and their structural
performance at the serviceability limit state.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
FF3 APPARATUS
The following apparatus shall be required:
(a)
Test bed A structurally rigid test bed shall be used for supporting the pole. When it
is tested horizontally, provision shall be made for suitable low friction supports to
minimize the bending moment induced by the mass of the pole and to reduce
horizontal friction.
(b)
Bearing blocks When required, 300 mm wide bearing blocks shall be used for
holding the pole in position. The blocks shall be designed and shaped so that the pole
will not be subjected to excessive crushing loads during testing. The bearing block at
the pole butt shall be 50 mm from the butt of the pole as shown in Figure GG1. The
location of the ‘ground line’ bearing blocks (Dimension A in Figure GG1) shall be as
specified by the designer.
(c)
Bearing plate For baseplate-mounted poles, a rigid steel plate with overall
dimensions not less than those of the pole baseplate, fitted with threaded studs
corresponding to the size and centres of the pole holding-down bolts and a means of
fixing it to the test bed.
(d)
Loading device An appropriate device shall be used to apply the test load. The
device shall be capable of steadily applying and continually recording (or displaying)
loads, to a value greater than the relevant maximum test load and with an accuracy of
±2% of that maximum.
(e)
Deflection recording device Deflection recording device(s) shall be utilized to
measure the deflection at or near the load application point, as well as the deflection
at the bearing blocks if applicable, to an accuracy of ±10 mm for the load application
point.
FF4 TEST LOADS
FF4.1 General
Test loads for the strength and serviceability limit states shall be determined in accordance
with Paragraphs FF4.2 or FF4.3 as appropriate.
COPYRIGHT
297
AS/NZS 7000:2016
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Required test loads shall be determined by the designer with consideration of the following:
(a)
Limit state being tested (i.e. serviceability or ultimate).
(b)
Whether the intent is to proof load the pole or destructively test (in-grade testing).
(c)
Additional load required above the required capacity to ensure the desired level of
confidence in the capacity. This shall be statistically based where possible.
(d)
Distance between the top of the ground line support and the load application point to
ensure the required ground line bending moment is achieved.
(e)
Angle of applied load.
(f)
Second order effects.
(g)
Condition of the pole for old ex-service poles.
(h)
Serviceability limit state loads shall either be calculated from the actual in-service
design, or if this is not available the serviceability load shall be based on the ultimate
limit state test load multiplied by 0.6 or for concrete poles the determined crack width
stipulated for the environment the poles are to be used, that is 0.1 mm, 0.25 mm or
0.3 mm.
(i)
Likely point of maximum moment for the pole. The maximum moment may be below
ground and be higher than the ground line moment. This particularly important for
constant diameter poles, and poles tested when embedded in soil.
FF4.2 Strength limit state
The test load for the strength limit state shall be taken as either—
(a)
the maximum design bending moment for the strength limit state calculated from the
relevant loads determined in accordance with Section 6 and Clause 8.5.2.2 of this
Standard, divided by (hp + 0.15D); or
(b)
the design flexural strength at the cross-section of maximum bending moment (fRu),
calculated in accordance with the relevant material design Standard, factored in
accordance with Clause 8.5.2.2 of this Standard and divided by hp,
where
hp = the vertical distance, from finished ground level at the pole to the point of
attachment of the highest service carried by the pole
D = the total depth of embedment for direct planted poles; or
= 0 for baseplate-mounted poles
FF4.3 Serviceability limit state
The test load for the serviceability limit state shall be taken as—
(a)
the maximum design bending moment for the serviceability limit state calculated
from the relevant loads determined in accordance with Section 6 and Clause 8.5.3.2
of this Standard, divided by (hp + 0.15D);
(b)
0.6 times the value determined from Paragraph FF4.2(b); or
(c)
for concrete poles, when the crack width reaches 0.25 mm or the stipulated value for
the environment.
COPYRIGHT
AS/NZS 7000:2016
298
FF5 PROCEDURE
FF5.1 Direct embedded poles
The test procedure for direct-embedded poles shall be as follows:
(a)
If tested horizontally, mount the pole on the test bed by holding it in the appropriate
orientation between two bearing blocks at the spacing shown in Figure FF1.
The spacing of bearing (Dimension A in Figure FF1) shall be determined by the pole
designer, considering the worst case pole embedment depth in service (i.e. shallowest
embedment depth). Consideration shall be made to whether the pole will be installed
hard against a concrete gutter or rigidly with a concrete path.
NOTE: The test bed arrangement indicated in Figure FF1 could produce stresses in the
vicinity of the normal ground line, which are greater than those normally expected in practice.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
For poles of conventional design, such increase in stress is not of significance. If a
pole design requires cable entry holes or similar arrangements that reduce pole
strength in the region of the nominal ground line, the method of supporting the pole
for type testing may be modified.
(b)
If tested vertically, embed the pole in an appropriate foundation material for the
minimum depth specified for that material. Alternatively, support and secure the pole
with bearing blocks located as for Step (a), but rotated into a vertical plane and a
support provided under the butt.
(c)
Attach the loading mechanism (sling, chain, rope, hydraulic ram, etc.) to the pole at
the desired load point. Normally this would be between 100–300 mm below the pole
tip, but it may be elsewhere if an abnormal configuration is being tested. If the
loading device has the potential to slip off the pole and over the tip, it shall be
suitably restrained from doing so. Note, however, that this would also indicate some
tension induced into the pole. This can be avoided by ensuring that the load is angled
slightly below the ‘horizontal’ at all times during the test. Either way, it is critical to
know the angle of the applied load at all times during the test.
(d)
Apply the load in increments of either 10% of the test load or a force increment of
0.5–2 kN depending on the type of pole to be tested, the type of data required and the
expected capacity. Measure load and associated deflection at each increment up to
50% of the required or expected capacity.
(e)
Maintain the load reached at the end of Step (d) for 2 min.
NOTE: This is not necessary for some pole materials like timber or steel poles, and can be
omitted at the designer’s discretion.
(f)
Reduce the load to zero when it reaches 50% of the strength limit state test load and
measure the permanent set if any.
NOTE: This is not necessary for some pole materials like timber or steel poles, and can be
omitted at the designer’s discretion.
(g)
Reapply the load in increments of either 10% of the test load or a force increment of
0.5–2 kN, depending on the type of pole to be tested, the type of data required and the
expected capacity. Measure the load and associated deflection at each increment up to
the required test load or to failure, whichever occurs first. If nominated by the
designer, maintain the load for 2 min at each load increment (not necessary for some
pole materials like steel and timber).
(h)
Measure the deflection of the pole at the desired locations at each load increment up
to the required test load. Deflection measurements beyond this would be useful, but
should only be collected if safe to do so.
COPYRIGHT
299
AS/NZS 7000:2016
If failure has not occurred before the end of the holding period at the required test load,
continue increasing the load at increments to be determined by the designer, considering the
type of material and expected capacity, until the pole fails in an inelastic manner (fracture
or local buckling).
R ul e to m e a s u r e d ef l e c ti o n
a t t a c h e d to p o l e
A
B
50 mm
C
Block
Ground line mark
Timber or
rubber
p a c ke r
Laser light
l o c a ti o n
Block
Timber or
r u b b e r p a c ke r
W i d t h of p o s t n ot
m o r e th a n 3 0 0 m m
Cross-pieces
Rollers
(Ø 50 mm
m i n.)
D
S m o ot h l eve l p a t h s
r e q u i r e d fo r r o ll e r s
D y n a m o m e te r to m e a s u r e
p u l l - a c c u r a cy ± 2%
Loading
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
PL A N VIE W
NOTES:
1
Dimension A = Embedment depth.
2
Dimension B = Distance between test bearing blocks.
3
Dimension C = Distance from the ground level point to the underside of the top bearing block.
4
Dimension D = Distance of the test load application point from the top of the pole.
5
Unless the load is assured of being applied at exactly 90 degrees to the unloaded centreline of the pole
throughout the entire load range, the angle of the applied load shall be measured such that it can be
accounted for at each load increment. It is advisable to ensure that there is some angle on the load toward
the pole ground line (i.e. small compressive load) throughout the full load range for increased safety.
6
Vertical deflection shall be measured and included in the analysis.
7
For timber poles, the required test load shall be reached within 5 min ±90 s. The properties of timber are
such that if required extension of this to 10–15 min would not have a significant effect on the results,
however, if the load can be reached within the 5 min without reducing the accuracy or safety of the testing,
it is desirable to aim for this.
8
The unloading, reloading and 2 min hold times are not required for timber poles and any other poles that
are proven to have significant effects from things like cyclic loading or cracking in concrete.
FIGURE FF1 HORIZONTAL POLE TEST APPARATUS
FF5.2 Baseplate-mounted poles
The test procedure for baseplate-mounted poles shall be as follows:
(a)
Mount the bearing plate on the test bed and fix the pole to the bearing plate, in the
appropriate orientation, by bolting the pole baseplate to the bearing plate studs with
nuts tightened to the manufacturer’s recommended torque.
(b)
If tested horizontally, support the poles at no less than two points along its length
with the low-friction supports specified in Paragraph FF3(a).
(c)
Continue as for Steps (c) to (h) of Paragraph FF5.
COPYRIGHT
AS/NZS 7000:2016
300
FF6 REPORT
The following shall be reported:
(a)
Type of pole.
(b)
Date of manufacture for concrete or steel poles.
(c)
Date of testing.
(d)
Reference to this test method, i.e. AS/NZS 7000, Appendix FF.
(e)
Geometric details of the pole.
(f)
Manufacturer’s serial/batch identification number.
(g)
Test loads and the corresponding pole (tip) deflections.
(h)
Permanent set, if any, after the serviceability test load has been removed.
(i)
Any deformation or other (permanent) damage resulting from the test.
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
Any other relevant information.
COPYRIGHT
Standards Australia
Standards Australia is an independent company, limited by guarantee, which prepares and publishes
most of the voluntary technical and commercial standards used in Australia. These standards are
developed through an open process of consultation and consensus, in which all interested parties are
invited to participate. Through a Memorandum of Understanding with the Commonwealth
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
government, Standards Australia is recognized as Australia’s peak national standards body.
Standards New Zealand
The first national Standards organization was created in New Zealand in 1932. The New Zealand
Standards Executive is established under the Standards and Accreditation Act 2015 and is the
national body responsible for the production of Standards.
Australian/New Zealand Standards
Under a Memorandum of Understanding between Standards Australia and Standards New Zealand,
Australian/New Zealand Standards are prepared by committees of experts from industry,
governments, consumers and other sectors. The requirements or recommendations contained
in published Standards are a consensus of the views of representative interests and also take
account of comments received from other sources. They reflect the latest scientific and industry
experience. Australian/New Zealand Standards are kept under continuous review after publication
and are updated regularly to take account of changing technology.
International Involvement
Standards Australia and Standards New Zealand are responsible for ensuring that the Australian
and New Zealand viewpoints are considered in the formulation of international Standards and that
the latest international experience is incorporated in national and Joint Standards. This role is vital
in assisting local industry to compete in international markets. Both organizations are the national
members of ISO (the International Organization for Standardization) and IEC (the International
Electrotechnical Commission).
Visit our web sites
www.standards.org.au
www.standards.govt.nz
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
GPO Box 476 Sydney NSW 2001
15 Stout Street Wellington 6011
Phone (02) 9237 6000
(PO Box 10729 Wellington 6011)
Fax (02) 9237 6010
Freephone 0800 782 632
Email mail@standards.org.au
Phone (04) 498 5990
Internet www.standards.org.au
Fax (04) 498 5994
SAI Global Customer Service
Email enquiries@standards.govt.nz
Phone 13 12 42
Website www.standards.govt.nz
Fax 1300 65 49 49
Email sales@saiglobal.com
ISBN 978 1 76035 481 7
Printed in Australia
Accessed by VICTORIAN UNIVERSITY OF TECHNOLOGY on 19 Sep 2016 (Document currency not guaranteed when printed)
This page has been left intentionally blank.