Overhead Line Design Handbook V7
Overhead Line Design Handbook V7
Overhead Line Design Handbook V7
Version 7.0
Date August 2009
Table of Contents
INTRODUCTION
DESIGN PHILOSOPHIES
2.1
3
Basic Methodology
ELECTRICAL REQUIREMENTS
9
11
3.1
11
3.2
13
3.3
Transpositions
15
SELECTION OF CONDUCTOR
Steady state thermal current rating
Short-circuit thermal current rating
15
15
15
16
16
4.1
17
Sag-tension calculation
INSULATOR DESIGN
Design for pollution
17
18
22
22
22
23
ACTION ON LINES
24
SUPPORTS
26
FOUNDATION DESIGN
27
10
EARTHING
30
33
33
33
11
WORKED EXAMPLES
36
11.1
36
11.2
37
References
38
11.3
38
40
40
41
41
41
43
References
43
44
45
52
54
56
APPENDICES
57
APPENDICES
57
11.6
Conductor Clashing
57
12
59
12.1
59
12.2
59
12.3
Aesthetic Considerations
59
12.4
60
13
60
Terrain
61
Terrain Model
61
Alignment
62
13.1
72
13.2
73
13.3
Waterway Crossings
73
13.4
73
13.5
74
13.6
74
13.7
Ruling Span
75
14
75
15
77
15.1
77
15.2
77
15.3
78
15.4
79
15.5 Markers
Permanent Markers
Temporary Markers
Over Crossing Markers
79
79
80
80
16
VEGETATION CLEARANCES
80
17
83
18
COMMENTARY ON APPENDIX B WIND LOADS
Figure B 1 Wind Regions for Australian Design Wind Gust Types
B4. Downdraft wind regions (Australia Zone II and Zone III and New Zealand Zones
Region A 7 )
B4.1 Downdraft Winds
84
84
85
85
19
COMMENTARY ON APPENDIX D - GUIDELINES ON SERVICE LIFE OF
OVERHEAD LINES
88
20
89
Clause F1
General
90
22
L1
GENERAL PRINCIPLES
90
97
100
100
100
105
82
1.2 general
82
82
82
82
82
82
83
83
1.5 References
84
24
85
1.6 General
85
1.7 Mechanical
85
1.8 Electrical
85
1.9 Clearances
86
1.10 references
86
25
86
1.11 general
86
1.12 CC
86
1.13 CCt
86
1.14 Clearances
87
1.15 references
87
26
88
SELECTION OF CONDUCTORS
88
THERMAL LIMITS
General
Maximum design operating temperatures
Conductor permanent elongation
Fault ratings
88
88
89
91
92
INTRODUCTION
Scope
This Handbook is the second in the Overhead Line Design Standard suite of documents and is a
companion to the Standard. The Handbook steps the Designer through the design process with
application guidelines, relevant information and worked examples which comply with the
Overhead Line Design Standard.
The application guidelines will apply to both transmission and distribution lines used in Australia.
Typical distribution voltages in Australia and New Zealand are at 33 kV, 11 kV and 415/240
volts, commonly referred to as low voltage. Typical sub-transmission voltages in Australia and
New Zealand are; 66 kV and 110/132 kV and transmission voltages are; 220 kV, 275 kV, 330 kV
and 500 kV.
In particular, the Handbook has an emphasis on pole type sub-transmission and distribution lines.
An overview of the steps in the Overhead Line Design process is given in the flowchart below.
DESIGN PHILOSOPHIES
2.1
Basic Methodology
The design methodology involves the development of a suite of appropriate structures, insulation
and constructions for use at the various voltage levels to comply with the Overhead Line Design
Standard. The overhead line has to perform with suitable levels of reliability and security for the
weather loads expected in the region for its intended life.
Reliability levels
All overhead lines should be designed for a selected reliability level relevant to the lines
importance to the system (including consideration of system redundancy), its location and
exposure to climatic conditions, and with due consideration for public safety.
Design Working and Service Life
The design life, or target nominal service life expectancy, of the line is dependent on its exposure to
a number of variable factors such as solar radiation, temperature, precipitation, wind, ice, and
seismic effects.
The service life of an overhead line is the period over which it will continue to serve its intended
purpose safely, without undue maintenance or repair disproportionate to its cost of replacement
and without exceeding any specified serviceability criteria.
Structural components of the support must be able to withstand the ultimate design loadings
without failure within this period. This may include providing allowance for a reducing load
factor over time due to progressive degradation such as soft rot in timber pole elements and
corrosion of steel elements.
Security levels
Clause 6.2.1 of the Standard provides a framework for the designer to evaluate and select a standard of
design to suit a relevant security level appropriate to a particular line or a line construction class or type.
In this evaluation consideration must be given to the lines importance to the system (including any system
redundancy), its location, exposure to extreme climatic conditions, public safety and design working life.
Initially a generic Security Level is selected (as set out in Clause 6.2.2 of the Standard) to reflect the
importance of the line within the network.
Level I
Level II
Level III
Table 6.1 of the Standard provides Reliability load multipliers for each Security Level relative to a range
of design working life options.
The design wind loads for an overhead line are be based on 50-year return period wind speeds
as defined in AS/NZ 1170.2. The calculated wind loads shall be then multiplied by an
appropriate reliability load multiplier based on the required security level and design life as
selected from Table 6.1.
As the design working life or security level increase so to do the wind and other applied loads
proportionally increase as the load multiplier increases.
TABLE 6.1
RELIABILITY MULTIPLIER FOR DESIGN WORKING LIFE AND
LINE SECURITY LEVELS
Minimum reliability load multiplier M rel
Line security level
Design working life
Level I
Level II
Level III
0.67
0.67
0.77
< 5 years
0.77
0.9
1.0
25 years
0.9
1.0
1.2
50 years
1.0
1.2
1.4
100 years
1.2
1.4
1.4
These Multipliers are applied to loads derived from 50-year return period wind speeds as defined in
AS/NZ 1170.2.
AS/NZS1170.2 provides regional design wind velocities VR for a number of wind regions and design
return periods. The load multipliers tabulated in Table 6.1 above have been derived from an analysis of all
regional values of VR and expressed as a factor (VR /V50)2 against each design life.
When these load factors are applied, a probability of exceedance equivalent to that provided in AS/NZS
1170.2 for each of these return periods / design life values will be provided.
The standard also refers in Notes to Table 6.1 to giving consideration to the line length, number of
circuits and proximity to other lines or infrastructure, special exposed locations such as long span water or
valley crossings, or line locations where access is difficult (where time and cost to restore the construction
can be high). In these cases a higher security level could be adopted for a particular structure or short
sections of the line, or the whole line.
Design wind velocities greater than the regional value of V50 values in AS/NZS 1170.2 could be used if
considered more appropriate however the simplest approach is to increase the design working life.
.
ELECTRICAL REQUIREMENTS
3.1
From safety considerations, overhead conductors should maintain requisite clearances to ground,
over roads, rivers, railways, tracks, telecommunication lines, other existing power lines.
The ground clearance for different voltages at maximum design temperature are given in Table 3
[ Table 3.7 of Overhead Line Design Standard].
TABLE 3
CLEARANCE FROM GROUND, LINES OTHER
THAN INSULATED SERVICE LINES
Distance to ground in any direction
m
Nominal system voltage
Over the
carriageway of
roads
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
7.5
7.5
6.0
X 2 + (1.2Y ) 2
U
+ k D + li
150
where
X
is the projected horizontal distance in metres between the conductors at mid span;
3.2
is the projected vertical distance in metres between the conductors at mid span;
is the r.m.s. vector difference in potential (kV) between the two conductors when
each is operating at its nominal voltage.
is a constant, normally equal to 0.4. Where experience has shown that other
values are appropriate, these may be applied.
is the greater of the two conductor sags in metres at the centre of an equivalent
level span and at a conductor operating temperature of 50C in still air
Ii
is the length in metres of any free swing suspension insulator associated with
either conductor.
There are a number of electrical clearance which determine the tower top geometry. These
clearances are:
(A)
(B)
(C)
(D)
These clearances are shown in Figure 2. To determine the swing angle from the wind pressure
Appendix R of the Detailed Procedure can be used with the following guidelines:
(1)
The transverse force is derived from the conductor diameter and wind span
(2)
The vertical force is derived from the conductor weight (N/metre) times the weight span
(3)
(4)
In general the weight and wind area of the insulator can be ignored
The vertical clearance between earthwire and top conductor, is governed by the desired lightning
performance and angle of shielding. The shield angle generally varies from about 250 to
400,depending on the configuration of conductors.
Blowout clearance calculations are useful to determine clearances along the span to structures
along the route.
The recommended conditions for calculating blowout are:
(1)
(2)
(3)
3.3
Transpositions
Transpositions may be required on long transmission lines or heavily loaded lines to reduce the
level of negative sequence voltage unbalance and reduce the interference in adjacent
telecommunication circuits.
SELECTION OF CONDUCTOR
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 convection
cooling and Pr is the radiation cooling. The terms for heat gain for cyclic
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.
Corona Effect
For high voltage lines generally above 100 kV, the conductor size may be determined on the
corona performance which can cause adverse impacts such as Radio Interference
Voltage (RIV), and Audible Noise. The surface voltage gradient on the conductor should be
around 16 kV/cm or less to limit the generation of corona discharges.
Mechanical strength
The mechanical strength of the conductor is one of the major parameter during the selection of the
conductor of the line.
Conductor Limit states
The overhead line is considered intact when its conductors and or tension fittings are used at
stresses below their damage limit.
When subjected to increasing loads, conductors and or tension fittings may exhibit at some level,
permanent deformation particularly if the failure mode is ductile; or for wind induced aeolian
vibration, conductors may exhibit wire and or whole conductor fracture. This level is called the
damage limit and conductors and or tension fittings will be in damaged state if the conductors and
or tension fittings have exceeded the damage limit.
If the load is further increased, failure of the conductor and or tension fittings occurs at a level
called the failure limit. The conductors and or tension fittings will be in a failed state if the
conductors and or tension fittings have exceeded the failure limit.
The state of system and the damage and failure limits are illustrated in Figure 1 [ Section 2.2.1.2 of
Overhead Line Design Standard]
Table 2 gives the damage and failure limit for a bare conductor.
TABLE 2
DAMAGE AND FAILURE LIMITS OF CONDUCTORS
Conductors and tension fittings
Damage limit
Failure limit
Lowest of
Bare
Sag-tension calculation
The sag and tension of the conductor are subject to variations due to the changes in temperatures
and loading. For spans of the order of 300 meters and less, the sag and tension calculation can be
carried out by parabolic formula with sufficient degree of accuracy. For the case of very long
spans, catenary formula gives more accurate results than parabolic.
Parabolic formula:
SAG =
wL2
8T
Catenary formula:
SAG =
c cosh
2c
INSULATOR DESIGN
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.
Air gap clearance refers to the minimum distance which must be maintained between the live
conductor and earthed metal parts of the support to avoid flashover. The minimum air clearance
has to be maintained even under the conditions of system over-voltages with the insulator strings
in the deflected position due to the action of wind pressure. The three types of over voltages
which can occur on overhead lines are:
1. Lightning induced
2. Switching surges
3. Power frequency over voltages
Design for pollution
For medium to high voltage lines, the pollution performance of the insulator usually dictates the
amount of insulation is required for the particular voltage. When determining the insulation
requirements in a contaminated environment, the following criteria need to be considered:
(a)
(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.
WORKED EXAMPLES:
Transmission Line Insulator Examples
Calculate the strength of a tension ceramic disc insulator used for oxygen conductor strung to everyday
tension of 20% CBL.
Based on Appendix DD, the state to determine the mechanical design is the ultimate strength state.
(a)
everyday load
The determining state is the failure containment load where the maximum design
cantilever strength is 6800 N.
(2)
A 2.5 inch post insulator is typically rated at 6 kN MDCL and is not appropriate for
this load
(3)
Calculate the strength of a suspension composite long rod used to support oxygen conductor with a weight
of 0.925 kg/metre, weight and wind span of 400 metres, and strung to everyday tension of 20% CBL. For
broken conductor condition assume a serviceable wind of 500 Pa.
(a)
everyday load
Longitudinal load = 22700 N * 0.7 factor (load relief due to insulator swing) = 15890 N
Component strength factor for long rod insulator = 0.5 (Table 6.5)
Insulator specified mechanical load = 15890 / 0.5 = 31780 N
Comments:
(4)
The determining state is the failure containment load under broken conductor
conditions
(5)
The minimum recommended size for the suspension insulator is 111 kN (specified
mechanical load). The SML is a one minute withstand load.
(6)
If a ceramic disc insulator would be used, then the recommended minimum size is 70
kN (minimum breaking load).
(7)
Calculate the strength of a ceramic line post insulator used to support moon conductor in a clamp top with
a weight of 0.34 kg/metre, weight span of 100 metres, and strung to everyday tension of 20% CBL.
(f)
everyday load
Tension string
Suspension or I string
Line post
Pin (G Bailey to provide)
Vertical load
Transverse load
Longitudinal load
Vertical loads
Vertical loads include the weight of conductors, earthwire, crossarms and pole mounted plant.
Transverse loads
Transverse loads are caused by wind on conductor and structure and horizontal tension from
deviation angle in the line.
Longitudinal loads
Longitudinal loads are caused by difference in conductor tension on either side of termination
structures, adjacent spans being of different lengths and an abnormal (broken wire) load on the
structure.
Wind load
A complete coverage of wind loading is given in Appendix B of the Overhead Line Design
Standards.
The design site wind speed is taken as
Vz
where
Mz,cat =
Md
Ms
shielding multiplier.
Mt
V50
basic regional wind velocity for the region corresponding to the 50 year return
period.
qz
MRel =
x
are load factors which take into account variability of loads, importance of
structure, stringing, maintenance and safety considerations etc.
Wn
wind load based on a 50 year return period scaled by the appropriate reliability
load factor or specified design wind pressure
the strength factor which takes into account variability of material, workmanship
etc.
Rn
Some of the Limit State load cases given in the Overhead Line Design Standard are as follows:
The Ultimate Strength Limit State Condition
ACTION ON LINES
Temp
Wind
Maximum
Tension
Refer Table Z1
Fatigue
Endurance
Conditions
Design
Everyday
Condition
Ultimate wind
Design at 0.5 to
7 m/sec
0 Pa
Refer Table Z1
Regional design
value
.5 CBL for
linear
.7 CBL for nonlinear
Initial / Final
Final
Servicability
wind electrical
Cold Condition
500 Pa
.5 x CBL for
linear
.7 x CBL for
non-linear
Final
0 Pa
0.3 x CBL
Initial
0 Pa
0.3 x CBL
Initial
0 Pa
Everyday
tension plus
creep factor
0 Pa
1 to 5 year
return period
(300 Pa
nominal)
30 Pa
0 deg C
Temp at time of run
out
Temp at time of pretension
Temp at time of
sagging minus creep
correction factor
Avg ambient temp for
year
100 Pa
.25 x Ult wind
Note: The relevant temperatures for a selection location is available from the Australia Bureau of
Meteorology (BOM) website or NIWA for New Zealand
Establishment of loads cases - J McCormack, B Clulow and J Giles
Include basic limit state wind pressure for distribution designs; - B Clulow, R McLennan
Modify wind pressures for various drag coefficients for poles and Regions/ Topography R
Fairweather and L Elder
Application Table
Overhead Line
System
Line Component
or Parameter
Ultimate
Support System
(structures and
foundations)
Structures
detailed
Ultimate wind
Everyday
procedure
Pole detailed
procedure
Ultimate wind
Pole simplified
method
900 Pa in
Region A & B
Deflection Limit
at serviceable
wind
Deflection Limit
at 300 Pa
0 Pa
Electrical
System
Clearances
low wind
Clearances
moderate wind
Clearances
high wind
Clearances
Maintenance
60 to 100 Pa
100 to 300 Pa
500 Pa
60 to 100 Pa
Conductors
Insulators
tension
Insulators vee
string
Insulators post
or pin
Ultimate or 900
Pa
Ultimate
conductor
transverse or
Failure
containment
Ultimate
conductor
transverse or
Failure
containment
500 Pa
0 Pa
Fittings
8
SUPPORTS
900 Pa to conductor
1300 Pa to round pole (this allows for crossarms, pole steps, insulators but not metal clad
plant)
These wind pressures allow for span reduction factors, drag factors and terrain categories 2 to 4.
For stayed poles, the vertical loads due to the stay reaction forces needs to be taken into account.
The relevant multiplier for the vertical loads produced by the stay is 1.25 ??.
0 Pa for conductors
0 Pa for round surfaces such as poles
A deflection serviceability limit will apply to concrete poles which may crack under load.
The maximum crack width is typically in the range 0.1 to 0.3 mm (refer Appendix D3.7) with
a maximum deflection limit at 5% of the pole length.
FOUNDATION DESIGN
Uplift
Downthrust
Lateral load
Overturning moment
Foundations for supports may take the form of single foundations in the case of pole type structures
and guy anchors or separate footings for each leg of towers.
The loading on single footings is predominantly in the form of overturning moment, which is
usually resisted by lateral soil pressure, together with additional shear and vertical forces resisted
by upwards soil pressure.
Common types of single foundations are direct buried poles, bored caissons, mono-bloc footings,
pad or raft footings, bored pier foundations, and single pile or pile group foundations.
When separate footings are provided for each leg the predominant loadings are compression and
uplift forces, however, shear forces should be considered.
Uplift and compression forces are usually resisted by combinations of dead weight of the foundation
bulk, earth surcharges, shear forces and bearing in the soil. This also applies to guy foundations.
Common types of separate footing foundations are (stepped) block footings with or without
undercut (pad and chimney, spread footings); auger bored footings with or without expanded base;
pier or caisson foundations; grillage foundations; and vertical or raked pile foundations.
Formula
Precise calculation,
Advantage
/ Comment
Disadvantage
Complex,
requires
soil
modelling
AS4676
Formula
C(b) 1 pre 10% pole length + 0.6 Simple
1992
to 0.8
New Zealand
Pole length / 6
Simple
The simplified embedment depth formula is given in Equation 13.2 (from AS4676).
Example:
Servicable wind at 500 Pa on conductors and 750 Pa on pole
Pole Tip Load, Hg = 8 kN
Height = 14 m
Normal soil cohesive strength, Fb = 300 kPa
Pole dia, b = 0.35
Embedment Depth = 2.22
This depth correlates with a traditional rule of thumb of 10% of the pole length + 0.8 m
Ultimate wind at 900 Pa on conductors and 1300 Pa on pole
Pole Tip Load, Hg = 14 kN
Height = 14 m
Normal soil cohesive strength, Fb = 300 kPa
Pole dia, b = 0.35
Embedment Depth = 2.41
Variation of soil cohesive strengths
For low cohesive strength soils, the options are:
(1)
(2)
Increase the embedment depth for the above case, with 150 kPa soil, the embedment
depth is 3.23 m under serviceable wind and 3.5 m under ultimate wind
Increase the effective width of pole by installing a sand/cement backfill in the hole for
the above case with 150 kPa soil to achieve the same foundation strength, a hole of
diameter 700 mm will be required for both serviceable and ultimate wind loads
To achieve a consistent above ground height (for clearances), option 2 is generally preferred.
10 EARTHING
An earthing system of overhead earthwires, earth down leads, grading rings and counterpoise
earthing addresses the following objectives:
(d)
(e)
(f)
Control touch and step potentials around the base of the structure.
(g)
(h)
(ii)
To withstand, from a thermal point of view, the highest fault current as determined by
calculation
It is a desirable goal to achieve an average structure footing resistance for the line of less than 10
ohms. This can ensure the lightning performance of a line is acceptable and ensure touch and
step potentials are at an acceptable level. The structure footing resistance can be controlled
during the construction phase of the line by installing additional earth rods or counterpoise wires
in the soil away from the structure.
Practical Earthing Schemes T Gillespie
Design for Touch and Step Potential for conductive structures
The range of mitigation measures to address touch and step potentials are:
1. Installation of overhead and underslung earthwire
2. Installation of grading ring
3. Reduction of footing resistance
4. Installing high conductivity earthwires
5. Installation of high resistivity surface layer (eg ashphalt)
6. Installation of NER or NEX on zone transformer to limit earth fault current
7. Connection to CMEN earthing system
8. Insulating base of pole
9. Installing a fence around conductive structure
10. Appropriate insulation of low voltage circuits
Replacing a non-conductive pole with a conductive pole
When replacing a non-conductive pole with a conductive pole, due consideration needs to be
taken to address step and touch potentials.
SWER Earthing
For public safety, a SWER high voltage earth needs to be restricted to around 20 volts or less
(Queensland Code of Practice for Works Earthing)
HV Distribution Earth (eg Pole mounted transformer, recloser, air break switch) in a CMEN
urban area
Voltage = 11 kV
Fault Current = 5,000 A
Fault Clearing Time = 1 sec
Fault Rate = 2 x 100 m span without earthwire at 40 faults per 100 km per year
Contacts per year = 40 for 4 seconds
Footwear = standard distribution
Earthing resistance = 1 ohm
Soil resistivity = 100 ohm-m
Prospective Touch Voltage = 1,000 Volt (derived by impedance model of footwear and soil
resistivity)
Prospective Touch Voltage Curve DU for 1 sec clearing = 800 Volts
Mitigation Options:
(1)
Insulate earth (this is standard practice for HV earth downleads but may not be practical for
air break switches with exposed metal operating rod and handle)
(2)
(3)
(4)
Reduce protection clearing times at 0.5 seconds, the prospective touch limit is 4,000 volts
Voltage = 11 kV
Fault Current = 5,000 A
Fault Clearing Time = 1 sec
Fault Rate = 2 x 100 m span without earthwire at 40 faults per 100 km per year
Contacts per year = 40 for 4 seconds
Footwear = standard distribution
Earthing resistance = 10 ohm
Soil resistivity = 100 ohm-m
Prospective Touch Voltage = 10,000 Volt (derived by impedance model of footwear and soil
resistivity)
Prospective Touch Voltage Curve DU for 1 sec clearing = 800 Volts
Mitigation Options:
(1)
Insulate pole (there have been trials on networks but no proven product is available)
(2)
Installation of NER or NEX to limit fault current to typically 1000 A prospective touch
voltage reduces to 2,000 volts. This is still above limit
(3)
Installation of grading ring this would lower prospective touch voltage to around 5,000
volts. This is still above limit.
(4)
Reduce protection clearing times at 0.5 seconds, the prospective touch limit is 4,000 volts.
The prospective touch voltage is above limit.
(5)
(6)
(7)
Installation of underslung earthwire this reduces prospective touch voltage to less than 800
volts (underslung earthwire is expected to reduce fault current on striken pole to range of 5 to
8% of previous value). This meets limits.
The installation of underslung earthwire is also effective in addressing touch hazards on all
conductive poles on the feeder.
A failed stay wire can fall onto live conductors and bring an energized stay wire closer than 2.4
metres in height from the ground. The following diagrams showing various broken stay wire
scenarios.
To protect for these scenarios more than one stay wire insulator may be required.
11 WORKED EXAMPLES
11.1 Electrical Clearances between conductors
Example 1:
Single circuit 19/3.25 AAC at 33 kV 3 phase on pin insulators in a delta configuration with a
span of 200 m. What is the mid span vertical separation required between phases if a crossarm
with a separation of 2.1 m between outer phases is used?
Sag at 50 degrees C is 6.07 m and sited in Region A.
Refer Figure 10.3.1.
where
X
1.05
33
0.4
6.07
li
X 2 + (1.2Y ) 2
U
+ k D + li
150
1.052 + (1.2Y ) 2
33
+ 0.4 6.07 + 0
150
0.591
1.2
Y 0.493
Therefore required minimum vertical separation for centre phase is 0.493 m.
Example 2:
Upper circuit 19/3.25 AAC at 33 kV 3 phase on pin insulators in a delta configuration with a
span of 200 m located directly above the lower circuit. The lower circuit conductor is 19/.064
copper at 11 kV. The lower circuit has a 120 phase differential to the upper circuit.
What is the mid span vertical separation required between circuits if a crossarm with a
separation of 2.1 m between outer phases is used?
Sag at 50 degrees C is 6.07 m 19/3.25 AAC and 5.81 m for 19/.064 Copper sited in Region
Type A.
Refer Figure 10.3.2.
Because the circuits are located vertically above each other the horizontal component is taken
as zero and
U
33 11
33 11
Cos120
+
2
3
3
3 3
22.9 kV
22.9 (the difference in the vector r.m.s. potential of the circuit voltages)
0.4 (Region A)
li
0 (Pin insulators)
X 2 + (1.2Y ) 2
0 + (1.2Y ) 2
U
+ k D + li
150
22.9
+ 0.4 6.07 + 0
150
1.138
1.2
Y 0.948
TABLE 4.1
AMBIENT TEMPERATURES AND WIND SPEEDS
FOR CONDUCTOR RATINGS
Rating type
Ambient temperature
(C)
Wind speed
(ms 1 )
0.5 to 1.0
1.0 to 2.0
0.5 to 1.0
1.0 to 2.0
References
1
Electricity Supply Association of Australia, D (b) 51998, Current Rating of Bare Overhead
Line Conductors published by Standards Association of Australia.
MORGAN, V.T. Thermal Behaviour of Electrical Conductors, Steady, Dynamic and FaultCurrent Ratings. Published in Brisbane by John Wiley and Sons Inc, 1991.
3.
IEC 60909 Calculation of the short-circuit currents in three phase a.c. systems
11.3
Lightning induced outages are one of the major cause of outages on overhead lines in areas of
moderate to high ceraunic activity. A moderate ceraunic level is between 30 and 50 thunderdays per
year, and high level above 50 thunderdays per year.
The acceptable outage rate due to lightning is therefore one of the most dominant design parameters
for an overhead line. In a low to moderate ceraunic activity area, an acceptable outage rate from
lightning for overhead lines with overhead earthwires is typically 2 to 5 outages per 100 km per
year.
Process for design balance shielding failures vs backflashover performance T Gillespie
and induces a voltage in it. A portion of current also flows down the conductive structure (or earth
down lead) to ground and develops a voltage on the structure. The magnitude of the voltage is
dependent on the structure surge impedance and the ground footing resistance. The lower the
footing resistance, the smaller is the reflection co-efficient and this results in a lower voltage on the
structure.
Distribution lines are generally unshielded and the major causes of lightning outages are direct
strikes and induced voltages from nearby lightning strikes.
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
(i)
installation of earthwire;
(j)
(k)
(l)
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 degrees.
The lightning performance of a shielded overhead line is complex and requires mathematical
modelling to determine the optimal shielding and backflashover rates.
The arc quenching properties 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. Refer to Reference [8] for the
electrical properties of wood. The effective impulse strength of a series wood and insulator path can
be calculated as follows:
Itotal =
...1
where
Iwood
Iinsulator =
When an overhead earthwire is installed on powerlines, generally a down lead is run to earth to
provide a low resistance path to ground. A low pole footing resistance not only reduces the
probability of lightning induced backflashovers but also offers the following advantages:
(a)
Reduces risk of injury to persons or animals due to rises in earth potential at the structure and
the surrounding soil.
(b)
Provides a low impedance path for earth faults to ensure there is sufficient fault current to
operate protection relays
Surge arresters can be applied to an overhead line to improve the lightning performance. Surge
arresters have been used in the following applications:
11.4
11.4.1
(1)
(2)
(3)
(4)
(5)
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:
1. Creepage (or leakage) distance.
2. The ability of the material to endure the electrical activity without being degraded.
3. The shape of the insulator to assist in reducing the likelihood of contamination collection and
facilitate washing.
There are two approaches which can be used to select the appropriate creepage distance for various
levels of contamination severity. The recommendations are given in Table 5.1 (titled Relationship
between severity of pollution at site to various parameters) of Reference [1]. Table 5.2 reproduces
the guidelines in Reference [2]. 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 5.2
GUIDE FOR SELECTING INSULATORS IN CONTAMINATED ENVIRONMENTS
ESDD range (1)
g/m
mm/kV
Light
0 to1.2
16
Medium
1.2 to 2.0
20
Contamination severity
Heavy
2.0 to 3.0
25
Very Heavy
Above 3.0
31
(1)
(2)
Ratio of leakage distance measured between phase and earth over the r.m.s phase to phase voltage of
the highest voltage of the equipment.
(3) Consideration should be given to increasing the creepage distances is areas where there are long
periods without rainfall or very close to the marine coast
11.4.2
Design for power frequency voltages (Wet withstand
requirement)
The line insulation should be designed to withstand the maximum voltage expected on the line.
Overhead powerlines usually operate at 1.1 per unit voltage to take into account the effects of
voltage drop with loading and there is the possibility that with capacitors on the line, the powerline
could operate up to 1.4 per unit which can be regarded as the maximum dynamic overvoltage.
Maximum dynamic overvoltage can occur during faults and load rejection. (1.4 per unit is for a
three phase power system that is effectively earthed e.g. the neutral is earthed). The wet power
frequency withstand voltage of the line insulation should be selected to exceed this maximum
dynamic overvoltage.
11.4.3
Switching surge overvoltages up to 3 per unit peak voltage can arise when overhead lines are
switched. The extent of this overvoltage is dependent on (1) the point of voltage wave when the line
is switched, (2) the capacitance or amount of trapped charges on the line and (3) 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.
A good coverage on the design for switching surge is given in AS 1824.2. When designing for
switching surges, one of the parameters which is difficult to obtain is the switching surge impulse
voltage. There are 2 main types of electrical tests conducted on insulators; one being the lightning
impulse and the other the power frequency flashover (wet and dry). Switching tests have been
conducted in laboratories and the flashover voltages have been inconsistent and found to be
dependent on the shape of the surge, the type of electrodes and the presence of earth planes.
In lieu of adequate test data on switching surges a good approximation for the switching surge
flashover voltage is 0.8 times the lightning impulse flashover voltage.
The insulator parameter that determines the insulator impulse performance ( i.e. switching surge and
lightning ) is the arc distance across the insulator.
Line insulation is usually selected independent of substation insulation. It is necessary to check
substation insulation impulse performance and install surge arresters, especially when the line
insulation is longer than the substation insulation.
11.4.4
Min Failing
Load (kN)
Min Creepage
Dist (mm)
Dry Lightning
Impulse (kVp)
70
70
70
70
280
360
280
360
95
95
95
95
Wet Power
Freq
withstand
(kVp)
40
40
40
40
7
7
22
18 (cantil)
6 (axial)
12 (cantil)
18 (axial)
12 (cantil)
18 (axial)
8 (cantil)
1.2 (kNm tors)
8.25 (OML)
25 (MML)
180
360
180
425
95
95
95
150
30
30
30
38
425
150
38
425
150
38
360
95
350
95
38
33 kV Insulators:
Min Failing
Load (kN)
Min Creepage
Dist (mm)
Dry Lightning
Impulse (kVp)
11
9 (cantil)
11 (axial)
9 (cantil)
11 (axial)
5 (cantil)
1 (kNm tors)
8.25 (OML)
25 (MML)
534
785
200
200
Wet Power
Freq
withstand
(kVp)
65
95
785
200
95
760
200
900
200
70
Example:
Select a suitable disc insulator string for a 33 kV line subject to extreme contamination. Normal
disc profiles have a creepage length of 300 mm and fog discs of 400 mm.
System Highest Voltage
36 kV
1116 mm
3.72 4 discs
2.79 3 discs
Select a suitable disc insulator string for a 275 kV line subject to heavy contamination. Use normal
or fog disc profiles where the creepage length is 300 mm normal and 400 mm for fog.
System Highest Voltage
300 kV
7500 mm
25 discs
18.75 19 discs
11.4.5
The loads on an insulator can be calculated using the Limit State methodology outlined in Section 3.
The guidelines for the strength factor are given in Table 3.1.
References
1.
2.
IEC 60815, Guide for the selection of insulators in respect of polluted conditions.
3.
AS 4436 Guide for the selection of insulators in respect of polluted conditions. (Identical to
ISO Report 815).
11.5
PZ
TX
TX
/2
/2
FT
PZ x D x W d
FT
PZ
D
Wd
TX
=
=
=
=
=
=
2 T X sin
11.5.1
Calculate the tip load on a 33 kV monopole with a Libra earthwire and Pluto phase conductors
vertically configured on the pole. There is also a line deviation of 20 degrees.
F1
2.4m
1.5m
d1
1.5m
F2
F3
F4
d2
d3
Fw
d4
(Load on pole)
20o
deviation
Input
Pole height
Earth wire
Conductors
Line deviation
Wind span
Average pole OD
Wind pressure
=
=
=
=
=
=
=
17.4m
Libra AAC (Tx = 5000N)
Pluto AAC (Tx = 13000N)
20o
180m
0.4m
900 Pa on conductor/OHEW, and
1300 Pa on pole
F1
Tip Load =
F1
=
=
+ 2 TX sin
Fw
2
3628 N
900 x 0.0188 x 180 + 2 x 1.25 x13000 x sin 10
=
Fw
d + d3 + d4
+
F2, 3, 4 2
d1
PW x OD x Wd
F2 , F3 , F4
8688 N
Pw x OD x d 1
=
=
F1
Tip Load =
d + d3 + d4
+
F2,3, 4 2
d1
15 + 13.5 + 12
3628 + 8688
+
17.4
Fw
2
9048
2
= 28.4 kN
SELECTION OF POLE
WOOD POLE
Select a pole with a limit state design load of 28.4 kN
Preserved wood pole component strength factor = 0.72 (Table 6.5 for range)
Ultimate Strength of Wood Pole = 28.4 / 0.72 = 39.4 kN
Wood poles typically decay during their life and designers may choose a pole with a higher
strength to achieve a longer design life.
Considerations for Un-stayed Pole
For an un-stayed pole, deflection limits need to be considered to ensure electrical clearances are
met and complaints are minimized from the public. The recommended deflection limits are:
Serviceable wind loads (typically 750 Pa wind on pole and 500 Pa on conductors) 5% of
the pole length out of ground
Ultimate wind loads (typically 1300 Pa on pole and 900 Pa on conductors) 15% of pole
length out of ground
STEEL POLE
Steel pole component strength factor = 1.0
Ultimate Strength of Steel Pole = 28.4 / 1.0 = 28.4 kN
F1
+ 2 TX sin
1747.7 N
500 x 0.0188 x 180 + 2 x9000 x sin 10
=
N
Fw
17.4m
Libra AAC (Tx = 2700N)
Pluto AAC (Tx = 9000N)
20o
180m
0.4m
500 Pa on conductor/OHEW, and
750 Pa on pole
PW x OD x Wd
F2 , F3 , F4
Tip Load =
=
=
=
=
=
=
=
4817.7
Pw x OD x d1
5220 N
F1
d + d3 + d4
+
F2,3, 4 2
d1
15 + 13.5 + 12
+
17.4
= 1747.7 + 4817.7
WOOD POLE
Maximum Working Load on Pole = 15.6 kN
Fw
2
5220
2
DESIGN DATA
1200
1200
11 kV Conductor type:
200
400
Dia
Mass
Area
2
CBL
(mm)
(kg/m)
(mm )
(MPa)
(/deg C)
(kN)
18.8
0.576
209.8
65000
0.000023
31.9
LV Bracket - ABC
10200
11 kV Conductor positions:
Conductor 1:
Conductor 2:
Conductor 3:
8700
Dia
Mass
Area
2
2300
CBL
(mm)
(kg/m)
(mm )
(MPa)
(/deg C)
(kN)
38.4
1.35
380
56000
0.000023
53.2
Pole details:
Mixed Australian hardwood classified to AS 1720.11997 as strength group S4 - stress grade
F17 (i.e. Jarrah, Ash type eucalypts)
Unseasoned, unpreserved and unshaved timber
Top diameter 300 mm
Ground line diameter 400 mm
Height above ground 10.2 m (i.e. depth in ground 2.3 m)
Crossarm size: 100 by 150 mm
11 kV insulators are ALP 11/275
The soil conditions are specified in three layers: 0-0.5 m of loose gravel with sand, 0.5-1.0 m
of firm cohesive soil and 1.0 m or more of very stiff cohesive soil.
CALCULATIONS
Use the approximate wind pressures based on Clause 3.4.1.
Conductor tensions are abbreviated as follows: for everyday load conditionEDT (i.e. every day
tension) and for short duration load conditionMWT (i.e. maximum wind tension).
11 kV Conductor load conditions (RS = 45 m)
Load
Ft = 1.60 kN
Ft = 1.79 kN
Ft = 4.58 kN
Ft = 2.96 kN
Fc = 2.01 kN
Load
Ft = 3.72 kN
Ft = 4.16 kN
Ft = 9.32 kN
Ft = 6.23 Kn
Fc = 4.47 kN
Determine Rn
Strength factor = 0.7 from Table 3.1
Rn
31.9 kN
Rn
22.3 kN
Conductor short duration load (MWT) = 6.87 kN, therefore for each 11 kV conductor,
capacity: 22.3 > 6.87, i.e. Rn > load is satisfied.
Capacity of 415 V cable
Determine Rn
Rn
37.24 kN
ABC Short Duration Load Condition (MWT) for 415 V cable = 13.98 kN
Capacity: 37.24 > 13.98, i.e. R n > load is satisfied.
Pole capacity
Determine Rn
Strength factor = 0.5 (from Table 3.1) to be applied on modulus of rupture determined from
AS 1720.1
M
k1
and k1 =
using
MWT
R n
EDT
where
Z = D 3 /32 = 0.0063 m3
Ultimate transverse wind load Wn will comprise wind loads on pole, conductor/cable and hardware:
wind on pole = 1.3 kPa (Clause 3.4.1(b))
pole wind load =1.3 0.5 (0.3 + 0.4) 10.2 = 4.64 kN acting 4.8 m above ground
wind on crossarm = 2.1 kPa (Clause 3.4.1(b))
crossarm load = 0.1 0.15 2.1 = 0.032 kN acting at 10 m above ground
wind on insulators = 1.4 kPa (Clause 3.4.1(c))
insulator load = 1.4 0.152 0.136 = 0.029 kN each, two acting at 10.2 m above ground and
one acting at 10.6 m above ground
wind load on 11 kV conductors = 0.9 47.5 0.0188 = 0.8 kN each, two acting at 10.2 m
above ground and one acting at 10.6 m above ground
wind load on 415 V ABC = 0.9 47.5 0.0384 = 1.64 kN acting at 8.7 m above ground
Therefore, taking moments about ground line
BM
62.5 kNm
0.8 10.2
Gs will comprise vertical loads due to weight of pole, weight of crossarms, insulators and other
ancillary hardware. This load is small in relation to the compressive strength of the pole and will be
ignored for this example.
Gc will vary for non-level terrain and unequal adjacent pole attachment heights, however for equal
height poles on flat terrain the conductor vertical loads are
Gc
0.27 kN
Gc
0.63 kN
62.56 + (1.25 0.134 0.63) + 1.5 (2 1.2 10.2 + 1.2 10.6 + 2.1 8.7)
145.87 kNm
Foundation capacity
Assuming that the pole met the design criteria the foundation can be designed using the ESAA
Brinch Hansen Pile program.
Using a foundation strength factor = 0.5 for foundations relying on empirical assessment from
Table 3.1, the ultimate ground line moment as calculated above is
BMult =
Hult
=
=
145.87 kNm and the ultimate shear load at ground line is:
Wn + 1.1G s + 1.25Gc + 1.5 Ft
4.64+0.032+3 0.029+0.8 3+1.64+1.2 3 1.5+2.1 1.5 = 17.35 kN
By entering the ultimate loads and soil properties obtained from Appendix B for each soil layer, the
ESAA BH Pile program output, as shown in Figure 3.2, delivers a minimum depth requirement of
2.6 m for a foundation diameter of 0.8 m.
Once a satisfactory pole and footing design for the maximum wind load condition is achieved, a
similar calculation may be followed for failure containment, maintenance and serviceability
conditions as appropriate.
The above calculations may also be accomplished by following the detail design approach given in
Appendix A.
Conductor Tensions for 7/3.00 AAAC (Fluorine) strung at 20% CBL at 15C
(Ruling span of 300 m)
Load condition
Load
Ft = 2.36 kN
Ft = 2.55 kN
Ft = 7.00 kN
Fc = 3.79 kN
Ft = 3.79 kN
NOTE: The conductor loads below exclude the weight of insulators and ancillaries.
From Clause 3.3.1 the ultimate strength limit state the maximum wind load is given by
Wn + 1.1G s + 1.25G c + 1.5Ft
For each conductor the contribution is:
Wn
1.25G c =
1.5Ft
1.305 285 0.009 0.666 = 2.23 kN (where 0.666 is the SRF for a 285 m
span)
1.25 0.135 285 9.81/1000 = 0.47 kN
1.5 7.00 = 10.5 kN
1.25G c =
1.2Fb
(the 0.45 factor is due to tension reduction resulting from insulator string swing where
span/sag = 45 and span/string length = 195 and derived from Figure 3.1)
Using the above approach, all the relevant loads for the ultimate, maintenance and serviceability
load cases can be calculated in a similar fashion to those in example
APPENDICES
11.6 Conductor Clashing
Under short circuit conditions conductors experience forces of attraction and repulsion due to
electromagnetic force from the fault current in the conductors. If the fault current is large and
experienced for a long enough time the movement can be substantial and cause conductor
clashing (particularly on distribution lines). For phase-to-phase faults the conductor movement is
more pronounced as the fault current is very high and the protection clearance times are typically
long.
Primary Conductor Clashing
Primary conductor clashing may occur when there is a phase to phase fault on one of two
overhead lines connecting the same substations. When a phase to phase fault occurs, one end of
the faulted line will usually trip first and fault current will then increase significantly on the other
unfaulted line. The increase in fault current may then cause the conductors on this line to clash,
resulting in the loss of two overhead lines. Constructions which are prone to conductor clashing
are underslung or suspension, flat pin and transitions from flat to vertical.
Secondary Conductor Clashing
Secondary conductor clashing may occur on a distribution feeder when a recloser trips and
isolates an initial fault and the live oscillating conductors upstream of the recloser subsequently
clash together. When the initial phase-to-phase fault occurs the faulted phase conductors repell
each other due to the current in the phase conductors. When the recloser trips the fault current and
thus the repulsion forces between the conductors is removed the conductors pendulum back into
equilibrium. Both phase conductors pendulum simultaneously towards each other and if they get
close enough they cause a secondary conductor clashing fault. Figure 2.5 below shows
diagrammatically the feeder, recloser and fault positions.
The repulsion forces can be great enough to exceed wind force design limits.
Conductor clashing has a higher probability of occurrence when the fault occurs on two adjacent
conductors at the same height and the conductor has low weight. Conductor clashing can be
avoided or mitigated by the following measures:
Appropriate consideration must be given at the route selection stage to the use of the land
proposed for the power line corridor. There are zoning maps available from local government
authorities which describe the land usage in the region.
Local jurisdiction planning instruments, particularly those regulating the clearing of trees, may
also influence the selection of the most appropriate route for the power line. Some areas may be
of high environmental significance such as aboriginal and cultural heritage or sensitive vegetation
(mangroves) and the line route will need to avoid these areas where possible.
Where power lines traverse private property the approval of the property owner is required. This
would normally take the form of a negotiated easement detailing any restrictions on land use
necessary for reliable operation of the line.
On public land the agreement of the management agency must be obtained for the proposed line.
12.1 Risk Management Principle
The layout design process should include the identification and assessment of risks associated
with the construction, maintenance and operation of the proposed line leading to the evaluation
and implementation of risk treatment options which ensure that the residual risk is acceptable to
the organization.
The risk management process used should align with AS/NZS 4360 Risk Management and
companion handbook HB 436 Risk Management Guidelines
12.2 Prudent Avoidance Principle
Where potential risks with unproven consequences are involved a prudent avoidance approach is
recommended.
The original recommendation related to electric and magnetic field exposures where prudent
avoidance was defined as doing what can be done without undue inconvenience and at modest
expense to avert the possible risk
12.3 Aesthetic Considerations
Visual amenity is now playing a major role in the selection of structures and other components on
an overhead power line to gain community acceptance. Visual amenity can be improved by
applying the following design principles:
- Locate power lines in corridors screened by vegetation or natural landscape
- Install like with like structures (if there is an existing tower line, select towers for the
second line in the corridor)
- Use of low height and compact structures
- Avoid placing structures which dominate the skyline
Compacting the phase conductors will improve visual amenity but will increase the surface
voltage gradient on the conductors and the noise (radio interference and audible). To offset the
increase in electric field strength, a larger diameter conductor may need to be selected to ensure
the surface voltage gradient is below the corona threshold level.
Non specular conductor will reduce the initial glare of the conductors and the high corona noise
produced when the line is initially energised. Non specular conductor will make the conductor
more hydrophilic to water and minimise the water drop corona effects.
12.4 Electric and Magnetic Fields
The principle of prudent avoidance has been adopted by the electricity industry for dealing with
electromagnetic fields from overhead lines (refer Section XXX). Where there are vertically
configured double circuit lines, electromagnetic fields can be minimised by diagonal phasing of
the phase conductors.
Where there are 2 or more circuits installed horizontally on the structures, it may also be prudent
to configure the phase conductors in a diagonal arrangement to minimise the electromagnetic
fields.
The layout design process involves the selection of a suite of structure types, the location of these
structures on a line corridor, the profiling of the conductors and the calculation of wind, weight
and ruling spans. The layout design shall ensure the following outcomes are met:
Acceptable electrical clearances to structures and ground for the voltage of line
Maximum adjacent span ratio selected to ensure longitudinal loading on insulators and
supports do not cause failures under adverse environmental conditions. The adjacent span
ratio is typically less than 3:1 (where there is free movement of conductors on insulators)
or 2:1 (where there is no free movement of conductors on insulators)
Weight to wind span ratio greater than 0.7 to ensure there are acceptable electrical
clearances on structures under wind conditions
Acceptable clearance of structures and conductors alignment to objects (eg buildings,
swimming pools, billboards)
Set back on roads appropriate to the speed of the road. These set backs can be reduced
where there are kerbing or natural barriers (drain or mounds)
Suitable foundation integrity (eg avoid side slopes)
Co-ordination with other Authorities and Services (Road, Rail, Water, Telecommunication
and Aerial Operations)
Designers need to ensure that the ground and environmental conditions are factored into the
layout process and need to consider for example the existence of steep slopes, existing and future
services, heritage sites, sensitive environmental areas, etc.
Terrain
A 3-dimensional GIS-type (Geographic Information System) terrain model is suggested for its
flexibility and compatibility with modern electronic surveying equipment and mapping
techniques. Terrain data are normally collected electronically (total station, photogrammetry,
lidar, etc.) and are subsequently downloaded into ASCII terrain files. A terrain model normally
includes information about the location and type of a large number of terrain or above-terrain
points. Above terrain points will be referred to as "obstacle" points. There are two ways to
describe an obstacle point.
You can either: 1) describe the obstacle by its height above a ground point and the coordinates of
that ground point, or 2) locate the top of the obstacle directly with its own coordinates.
Before generating a terrain, one should decide on broad categories of terrain or obstacle points
which have unique requirements. These requirements include minimum code clearances to be met
above or to the side of the points as well as symbols to be used to display these points on the final
drawings. (See Table 3.7)
Code clearances depend on the voltage of particular conductors.
If a point having the feature code is an obstacle described by its height above the ground, whether
to draw a line between that point and the ground or
If a point having the feature code is an aerial obstacle which your wires are allowed to pass under,
whether to check vertical clearances both above and below that point. whether a point having the
feature code is a ground point that will be used to draw a ground profile or a point that should be
by-passed when drawing the ground profile (for example the top of an obstacle), minimum
required vertical clearances above (and below for aerial points) points having the feature code and
minimum horizontal clearances to the side of these points for the voltages selected
Terrain Model
The XYZ model includes points described by their global coordinates X,Y,and Z.
The PFL model includes points described by their Station (cumulative distance from an arbitrary
reference point along the centerline of the line), Offset (lateral distance from the centerline) and
elevation, Z.
Also included for each ground or obstacle point are optional surveyor's notes to be displayed on
profile or plan views.
An XYZ file can be prepared and edited with a text editor or word processor or it can be created
by downloading survey data from an automatic instrument. There are many tools and techniques
available for importing and filtering XYZ terrain points data specially for LIDAR data which may
contain many millions of points.
Survey Information
The survey requirements for an overhead line design may include:
1. Width of the line corridor to be surveyed (which may be different than the easement
width)
2. Contour interval
3. Key features to be surveyed (fences, gates, roads, trees, railway lines, existing services)
4. Land use and limitations / constraints
5. Centreline and line deviations
6. Coordinate system and height datum
Alignment
The alignment (or alignments) of a project need to be defined before any engineering can be
performed. In the plan view, the alignments consist of straight line segments between PI points
(Points of Inflection). If you start with an XYZ terrain model, the alignments are defined in the
plan view by selecting the PI points. This is not required when using a PFL terrain model since
the alignment is implied (however, the PFL model is limited to a single alignment).
Once you have at least one alignment defined, you can create: 1) other independent unconnected
alignments, 2) alignment branches, or 3) alignment loops.
When you have multiple alignments you can build lines on all of them.
Values for the Maximum Offset for Profile View (MOPV) and the Maximum Offset for Centerline
Ground Profile (MOCGP) are to be selected. All ground or obstacle points within the MOPV
(measured from the center-line) are displayed with the appropriate symbols in the various profile
views, whether on screen or on a sheet of paper. Points outside the MOPV are not displayed in the
profile views. In addition, any structure or wire with an offset greater than MOPV will not be
shown in the profile view. Once you have an alignment defined on an XYZ terrain model, you
can create an equivalent PFL model.
The center-line is defined in the plan view as the collection of straight line segments connecting
alignment corners. The center-line ground profile is theoretically the intersection of vertical
planes going through the center-line and the ground. However, because the terrain data maybe
defined at discrete points within the line corridor, there is a need for rules to define how the
profile is displayed on drawings. The ground profile line displayed is a line that joins all ground
points within a specified offset from the center-line. That offset (MOCGP), is for two widths. The
points are joined in ascending order of stations. For example, if one selects a MOCGP of 3m, then
the profile line will pass through all the points within 3m of the center-line.
If there is significant side slope (perpendicular to the line) the line profile may look jagged when
it joins points of significantly different elevations on alternate sides of the center-line. If the
jaggedness of the profile line is objectionable, one may draw separate side profiles. Or better, one
may generate additional interpolated center line and side profile points using a Triangulated
Irregular Network (TIN) model of the terrain or by using breaklines.
Triangulating an XYZ terrain
The XYZ terrain model consists of individual points with their coordinates and feature codes .
The Triangulated Irregular Network (or TIN) model of the XYZ terrain is a surface made up of
triangles having the terrain points at their apexes using Delauney triangles.
The primary advantage of a TIN model over the basic XYZ model is that it is a surface and not a
collection of points. That surface can be used to generate accurate center line and side profiles, to
find the elevations of arbitrary points or to locate points at the intersection of latticed tower legs
or guys with the ground. The TIN surface can be rendered in different colors to give a more
realistic display of the ground, including elevations and light incidence. Bitmaps (aerial
photographs) can be projected onto it to give an even more realistic appearance of the terrain.
Break Lines
Break lines (or break line segments) can be used to enhance XYZ terrain models. While break
lines can be defined and displayed entirely by themselves, they are most useful in conjunction
with XYZ terrain points and TIN models.
A break line or break line string consists of break line segments. Each segment is a straight line
with known origin and end points. The location of each segment in 3-dimensions is fully known
from the global coordinates X, Y and Z of its two end points. Break line segments which have one
end in common are said to be part of the same break line string.
Using break lines to describe existing or planned facilities
Surveyors can provide data on portion of a larger terrain described by many thousands of break
line segments and an even larger number of XYZ points. Some of the break lines correspond to
yet unbuilt but planned road improvements.
PFL Terrain Model
The PFL terrain model requires that the center-line of the power line be defined first. The
locations of terrain or obstacle points are then described relative to that center-line. The station of
a point is the cumulative distance from an arbitrary reference point on the center-line to the
projection of the point on the center-line and its offset is its lateral distance to the center-line.
Positive offsets and positive line angles are defined as follows; If one travels the line in the
direction of increasing stations, positive offsets are to the right and positive line angles are
clockwise. Prior to the days of electronic surveying and computers, the PFL terrain
representation was used almost exclusively in power line work. Therefore, by tradition, many of
the early line design programs used that representation. However the XYZ model is more
powerful as it allows the designer to easily change a line route and to move a structure in the plan
view without being constrained by the existing center-line.
The data for a ground point in a PFL model include the feature code, an optional label or
description, the point station, its offset and elevation, the line angle at the location of the point (if
the point is on the center-line) and a zero obstacle height.
For an obstacle described by its height above a ground point, the data include the obstacle feature
code, an optional label or description, the station, offset and elevation of the ground point directly
below the obstacle, the line angle at the ground point (if on center-line), and the height of the
obstacle above the ground.
For an obstacle described by its own coordinates, the data include the obstacle feature code, an
optional label or description, the station, offset and elevation of the top of the obstacle, a zero line
angle and a zero obstacle height.
Also included for each ground or obstacle point are optional surveyor's notes to be displayed on
profile or plan views. Stations in a PFL file should be "true stations". They cannot be "equation
stations".
Using scanned raster drawings to create PFL terrain model
There are basically two approaches to building models of existing lines. The better approach is to
resurvey the terrain, the structure locations and the positions of the conductors with modern
equipment, i.e. to create a XYZ terrain model. A limited and less accurate alternative is to get the
locations of terrain, structure and conductor points from existing drawings or from scanned
images of these drawings. These drawings can be displayed in the background of the profile view.
Once the drawings are properly positioned in the profile view you need only digitize at locations
where you wish to create PFL points.
It is generally not recommended to use existing drawings as templates for building models of
older lines because of the potential accumulation of errors at each step of the process. The
original survey may have been inaccurate. The nature of the terrain below and in the vicinity of
the line may have changed over the years. The as-built locations of the conductor attachment
points may not be well reflected by the drawing. The catenary curves showing the positions of the
conductors at some temperature may have been based on crude assumptions not reflecting actual
sagging conditions and creep effects. These curves may have been drawn with templates not
adjusted to the actual ruling spans in the lines. The digitizing process itself, through scaling and
clicking on lines of finite thicknesses, will also add errors.
However, there are cases where one would want to quickly build a line model on top of a raster
drawing. You should make sure that the scanned drawing clearly shows labeled station and
elevation axes, with the station axis ideally labeled with true stations, as well as line angle
locations. This can be done before scanning by overwriting the axes with a dark pen. True
stations, that is stations measured from a point near the origin of the line can easily be calculated
and marked with a pen, if they are not already shown.
XYZ or PFL?
Given the choice of working with an XYZ or a PFL terrain model, the XYZ model is much better.
The alignment can easily be changed on top of an XYZ terrain model. There is no simple way to
change the alignment with a PFL terrain model as you do not have the ability to work in the plan
view.
With an XYZ model you can better visualize the terrain. A terrain TIN surface can be developed
and used for color rendering and the automatic display of contour lines. Maps and raster images
can easily be superposed to the plan view. Raster images can be projected onto the TIN surface
for realistic 3-d photo rendering of the terrain.
With an XYZ model, you can reference the locations of all your structures to the same coordinate
system used for the management of your line (GIS, databases, etc.). You can integrate a computer
model with other management tools used by your company.
While we highly recommend the use of the XYZ model over that of the PFL, you should
understand that both models are just alternate ways to look at the same 3-dimensional terrain and
alignment information. In fact, you can convert an XYZ model to a PFL model or convert a PFL
model to an XYZ model.
Side profiles, clearance lines, prohibited zones and special cost zones
Similar to the center line ground profile, side profiles are defined by an Offset from the center line
and an Offset Tolerance. All adjacent points (in order of increasing stations) within the Offset
Tolerance distance from the Offset line which are not separated by more than the Maximum
Separation will be connected to form a side profile. Side profiles are only shown where there are
terrain points within the specified Offset Tolerance.
A required clearance line (or several clearance lines if there are side profiles) can be displayed as
a dotted line and dotted spikes above the profile. The line and spikes are displayed for the voltage
specified. The clearance line consists of two parts. The first part is the basic ground clearance
consisting of copies of the centerline and side profiles shifted upward by a specified value. The
second part of the clearance line consists of vertical spikes indicating required vertical clearances
above (or below) specific terrain points or objects within the Maximum Offset for Profile View.
Prohibited zones and special cost zones can be defined along an alignment These zones are only
taken into account when optimizing the spotting of a line.
Equation stations
Once an alignment is defined, any terrain point has a station (distance along the alignment) and an
offset (distance from the center line).
"True station" is defined as the total distance measured from the first P.I. in the alignment to
which is added the designated station of that first P.I. The station of the first alignment point can
be changed from the default value of zero to any value.
"Equation station" is defined as a relative distance measured either forward or backward along the
alignment from an arbitrary point along the alignment. Unlike "True stations", "Equation stations"
are not continuous.
Design Criteria
Design criteria for power lines are often not the same in various countries and in different
companies within the same country. These criteria also change over time. However, in spite of
differences in particular numerical values, there are many similarities. General design check
functions could easily apply to a wide variety of design practices, from very simple requirements
for distribution lines to the most highly engineered processes for extra high voltage lines.
Modeling of wire system
One of the most complex parts of a transmission line is the wire system (conductors and ground
wires) in a tension section (from one dead end structure to the next dead end structure). Questions
arise regarding: 1) the handling of wind load which may not be uniform over the length of the
section (wind on individual spans may be larger than the average wind over the section because of
varying gust response factors and different wind incidences), 2) the handling of non-uniform ice
loads, 3) the handling of the many phenomena that generate longitudinal loads (broken wires,
slack redistribution, etc.), and 4) the possibility of interaction between flexible structures and all
wires in the tension section. Therefore, for practical design reasons, approximations and
assumptions have to be made.
There are several modeling levels are available to determine the response of the wire system to
some loading criteria. These levels are summarized as;
The simplest modeling level is based on the concept of the Ruling Span (RS) and it is sufficient
in most cases. The most advanced modeling level (Finite Element) is based on a full structural
analysis of the entire tension section, including detailed models of all supporting structures and all
cables. Because it is computer time intensive and is not justified in most situations, FE should
only be used in special cases where a very accurate representation of the interaction between the
structures and the wires needs to be considered. You likely will never have the need for this
advanced modeling capability (FE). Between RS and FE, there are some intermediate modeling
levels. These are defined herein as Real Span (because it works with actual real lengths of wires
in each span) or Finite Element (FE) modeling. The general assumptions used at these different
levels are discussed in this section.
Ruling Span method (RS) modeling - Usefulness and practicality of method:
This is by far the most practical method and it is applicable to the overwhelming majority of line
design situations. It should be used in all preliminary design situations. This is what you will use
most of the time. This method works well with legislated design loads which are generally
applied uniformly over a tension section. It should always be used at the preliminary design stage.
Assumptions:
1) The analysis involves a single wire (cable), in one or more spans, between dead ends, i.e. it is
assumed that there is no interaction between the wire and other phases of the same electrical
circuit or wires in other circuits.
2) The horizontal component of tension along the wire in all the spans of the tension section
between dead ends is constant, i.e. all intermediate supports are assumed to be perfectly flexible
in the longitudinal direction. This may not be very accurate in the case of rigid post insulators and
short suspension insulators subjected to large vertical loads. It is usually considered sufficiently
accurate in view of all the other uncertainties and approximations associated with line design.
3) Based on the horizontal component of its tension, the geometry of each span is determined as
the equilibrium configuration of a span is always a "catenary". The catenary lies in the plane
defined by the chord length of the span and the resultant wire load per unit length, UR, which is
assumed to have constant magnitude and direction at any point along the cable in a given span.
UR is based on the direction of the chord (a straight line), even though actual points along the
cable are below the chord. Without wind, UR is vertical and oriented downward. With wind, UR
is not vertical and it defines the swing angle of the span plane.
The catenary constant is the ratio H / UR, where H is the horizontal component of tension and UR
the load per unit length of cable. H is constant throughout the span.
The formula for ruling span is:
S3
L
L
L RS
Where:
S4
for inclined spans
Limitations:
1) All the spans need to be subjected to the same loading, i.e. this level of modeling is not capable
of analyzing situations with different ice thicknesses in various spans.
2) There is no way to study the effect of slack re-allocation due to moving a conductor attachment
point or cutting/adding some wire length in a span.
3) There is no way to account for support displacements in a system where there is a fixed length
of wire, for example inserting or raising a structure to fix a clearance problem without resagging
the wires.
4) This level of modeling cannot be used to model an existing line where unequal tensions have
been surveyed in various spans of a given tension section.
Finite Element (FE) modeling ignoring interaction between wires
Usefulness and practicality of method:
With this method, all supports (towers, poles and frames) are assumed infinitely rigid unless you
chose to insert fictitious springs between the supports and the insulators).
For conductors supported by latticed towers with suspension insulators, should give you better
sags at very high temperature than RS and very good approximations of unbalanced loading
situations.
Assumptions:
1) As with RS, the analysis involves a single wire at a time between dead ends, i.e. it is
assumed that there is no interaction between different wires (other phases).
2) An accurate finite element model of the wire in all the spans between dead ends is used. This
model is assumed in longitudinal equilibrium (i.e. the horizontal component of tension is assumed
to be the same in all the spans) for the sagging condition, i.e.for a specified weather case and
cable condition or unstressed lengths can be specified. Strain, suspension and 2-parts insulators
are modeled as structural elements. Attachment points at the tips of post insulators and at the
structure ends of strain, suspension and 2-parts insulators are assumed fixed in the vertical
direction, but can optionally be allowed to move in the transverse and longitudinal directions. The
transverse and longitudinal movements of the attachment points depend on their assumed
transverse and longitudinal flexibilities (or stiffnesses). With zero flexibilities, the supports are
fixed..
3) Once the tensions in all the spans of the tension section are determined (unlike with ruling
Span, you will get different tensions in different spans), the corresponding design loads are
calculated using the same procedures as used with RS.
Limitations:
With this model, you can apply different loads in different spans (unbalanced ice, broken
conductor, etc.), you can reallocate slack between spans and you can move attachment points.
However:
1) There is still no accounting of the possible mechanical coupling between wires in different
phases.
2) In the case of post insulators, it is difficult to know what value of longitudinal stiffness should
be used.
Finite Element (FE) modeling accounting for interaction between wires
This modeling is similar to modeling above, except that all the wires between two limiting
infinitely rigid dead end structures (the ends of the model) are analyzed simultaneously, thus
accounting for the possibility of some longitudinal interaction between the phases. If a dead end
structure is is being checked for strength with potentially different loads on each side, the limiting
dead end structures are at the ends of the tension sections to the left and to the right of the
structure being checked. If not a limiting dead end, a dead end structure is treated as any other
structure as far as its flexibility is concerned. The interaction between the wires is accounted for
through the flexibility matrices of the supporting structures between the limiting dead ends. With
the above model, you do not consider structure flexibility (unless you specify two flexibility
numbers at each support).
With this level, software determines a flexibility matrix at each structure. A flexibility matrix is
just a device to represent the behavior of a flexible structure without having to model it in its
entirety when you connect it to supported wires (Peyrot and Goulois, 1978).
Structure flexibility matrices are determined automatically by our software programs for Finite
Element structures. Therefore, there is no additional complexity required if you are already using
FE structures. Flexibility matrices include flexibility coefficients. Consider two insulator
attachment points, I and J,. These points can arbitrarily be located in space, for example " I "
could be a ground wire attachment point and " J " the structure attachment point of the insulator
supporting the lower left phase of a double circuit tower. If a single unit longitudinal load is
applied at point I, the corresponding longitudinal displacement J,I at point J is the flexibility
coefficient F . For a transmission structure with N attachment points, the I,J NxN symmetrical
matrix that includes all the coefficients F is called the structure longitudinal flexibility matrix. If,
instead of restricting yourself to longitudinal loads and longitudinal displacements, you consider
both transverse and longitudinal unit loads and their corresponding displacements, you get a
flexibility matrix of size 2N x 2N. This is in fact the flexibility matrix used by software at each
structure location when the wire system is modeled at FE considering wires.
Usefulness and practicality of method:
This method only works with FE structures, as the flexibility matrices for all the structures are
automatically re-calculated by programs when needed. Except for some additional computer time,
FE with conductors has all the advantages of FE without conductors without its limitations: it
accounts for the interaction between the wires and relieves you from having to assume a
flexibility value.
However, expect approximately an order of magnitude more computer time when you use FE as
compared to RS. This modeling is the recommended method when you have longitudinal load
issues in lines supported by flexible poles and frames.
Assumptions and limitations:
If a deadend structure is being checked for loads or is part of a tension section for which tensions
are calculated, its flexibility matrix, if available, is taken into account.
1) Interaction between the wires is modeled through structure flexibility matrices which are
inherently linear. Thus the nonlinear effects of extremely flexible poles and frames (which may
account for 10 to 20 percent of the stresses) cannot be accounted for. Guyed structures, which are
also highly nonlinear, may not exhibit the correct behavior.
2) The effect on the equilibrium of the system of the wind load applied directly to the structures
cannot be taken into account.
Full system analysis
At Finite Element models all the wires and supporting structures of an entire range of tension
sections as a single gigantic structure. A gigantic finite element model is created automatically
from the individual finite element models of the individual supports and the interconnected
cables. This method requires that you use FE structures.
Usefulness and practicality of method:
Due to the large number of nodes and elements in the gigantic finite element model that is used
internally, this method can be prohibitively computer intensive as it requires orders of magnitude
more computer time and memory than other models. However, you may be able to work around
the prohibitive time and memory demands by specifying that FE only be used for guyed or
flexible structures, while all latticed towers are modeled at otherwise.
Assumptions:
A Finite Element model includes few limiting assumptions unless wind is involved. The finite
element model is as accurate a model of your physical line as you can hope to get. There is
complete interaction between the wires through accurate behavior of the supporting structures,
including their nonlinear behavior.
Limitations:
While the idea of accurately modeling an entire line segment by finite element is theoretically
attractive, its practicality is limited.
1) You will rarely be able to justify the extensive time needed to run a full system model. It may
take a very long time to analyze just one load case.
2) Some regulators require that you apply load factors between the reactions at the ends of the
spans and the supporting structures. This is an impossible situation to model with FE for that
matter) since the structures will always respond to the unfactored loads provided by the cables to
which they are connected while your may dictate that you analyze and check the strength of these
structures under factored loads.
3) While we can apply a uniform wind to an entire model (same velocity and global direction
blowing on each and every span of a multi-spans model), this is not realistic. In fact we will never
know what would be an appropriate wind or even a legislated wind with gust response factors to
apply simultaneously to all wires and structures.
With Finite Element, the complete system is modeled to determine the tensions. It is assumed
that the wind direction on each span is either normal to the span, or is the same on all spans, i.e.
there is a global wind direction. The global wind direction is determined from your choice of
Wind Direction (other than NA+ or NA-). The unit wind load on each span is based on its gust
response factor which depends on the span length and average elevation.
Typical load cases for distribution and transmission lines are given in Section 6 of this Handbook.
There are usually a number of conditions for checking vertical, lateral and galloping clearances.
For checking the cables, the conditions may include: 1) the everyday combination, 2) no ice and
no wind at an everyday temperature, etc. Therefore, for a given project, the checks may contain a
substantial number of weather cases.
Weather Cases include data on:
Air density factor: Factor Q
Wind velocity or Pressure: Basic (or reference) velocity or pressure.
Wire Ice thickness, t: Thickness of ice assumed uniformly deposited on wire.
Wire Ice density, DENS:
Wire Ice load, Wice : Ice load per unit length of wire.
Wire Temp: Conductor or ground wire temperature
Weather Load Factor: Factor applied to wind and ice loads. Default = 1
NESC Constant, K: Constant K used only used for the NESC District Case
Wire Wind Height Select None, if you want your input values of wind velocity and pressure
Adjust Model: to be used on all wires and structures regardless of their height above ground
Wire Gust Response Gust response factor for all wires.
Conditions for cable creep and permanent stretch
The cable is assumed to be in its "Initial " condition for the few hours which follow its
installation. It is in its final after " Creep " condition after it has been assumed exposed to a
particular creep weather condition for a long period of time, say 10 years. It is normally assumed
that the weather case that causes creep consists of a no wind/ no ice condition at some average
temperature.
The average temperature of 15 deg. C is often used in Australia, unless the line spends several
months in very cold weather, in which case a colder value is appropriate. The final after " Load "
(also referred to as " final after common point " ) condition assumes that the cable has been
permanently stretched by a specified weather condition.
For example, .
Weight span
Depending on the method used to check the strength of your structures, you may need to calculate
a weight (or vertical) span. There are different ways, from very approximate to accurate, of
calculating weight spans.
For level spans, the weight span is equal to the wind span.
For inclined spans the distance between the low points in adjacent spans has no relationship
to the wind span. That weight span changes with different weather and cable conditions.
Therefore, a weight span can only be defined for a particular combination of weather and cable
conditions. When wind is blowing on inclined spans, it is actually difficult to locate the low
points in the elevation view. For a given cable tension, the location of the low point in the
elevation view depends on the swing angle of the entire span. In addition, the length of cable
between low points may be substantially different from the horizontal distance between these
points. Therefore, one should clearly understand the assumptions behind any weight span
calculation. Since weight spans are an indirect measure of vertical loads through the equation VL
= UV x VS, the validity of a particular method for calculating weight spans should be judged by
the ability of the method to predict correct vertical loads.
With traditional hand calculations and some computerized versions of these calculations, the
effect of the span swing angle is neglected. A catenary template corresponding to the resultant
load per unit length of cable is drawn in the vertical plane and the horizontal distance measured
between low points is taken as the weight span.
When structures are checked by the "basic allowable wind and weight spans" method (see Ruling
Span), the actual weight spans of their heaviest attached cable are compared to corresponding
allowable values for three weather conditions.
These conditions normally include a "wind", a "cold", and an "iced" condition.
Load trees for Finite Element structures.
When the strength of FE structures is checked, loading trees are established for a certain number
of "load cases" and are used for the analysis of the structures. There are many assumptions which
can be used to determine a loading tree.
.
Conductor sets
A cable "set" (also referred to as a tension section) is defined as a group or ensemble of one to
three cables (also called phases) with identical mechanical properties and tensions. For example,
an electrical circuit between dead ends is often modeled as one set. Corresponding to cable sets
are sets of structure attachment points and insulators (or attachment devices). For example a
double circuit tower, the two ground wire attachment points and attachment devices are made part
of Set #1,the three conductors in the left circuit and their suspension insulators are made part of
Deleted: Cable
Set #2 and the three conductors in the right circuit and their V-String insulators are made part of
Set #3.
If more than one attachment point on a structure is made part of a set, it is imperative that the
insulators (or attachment devices) at all attachment points of that set be identical. If two different
cables of the same circuit are not sagged at the same tension or if at any supporting structure the
insulators are not identical (for example one tower supports a circuit with an IVI insulator
configuration or with three I insulators of different properties), then they should be made
members of different sets. The only reason for grouping wires together in a set is that come
stringing and sagging time you can string the wires through all the attachment points within the
set and sag these wires simultaneously. If on the other hand you put each wire in independently (3
sets of one wire) then you will need to repeat the stringing and sagging operation three times,
once for each set. However, even with the time penalty associated with modeling only one wire
per set, there are several advantages to this approach: you can sag each phase separately and can
vary individual insulator properties at any location along the tension section.
When a set has more than one cable, each cable is identified by a "phase" number and its structure
attachment is identified by an "attachment" number. There can only be one, two or three phases
per set, therefore the "phase" or "attachment" numbers can only be 1, 2 or 3. When you string a
circuit, you have the ability to take any "phase" and attach it to any structure "attachment". This
allows you to transpose phases at intervals along your line.
Post insulators are handled differently when attached to Ruling Span structures as opposed to
Finite Element structures. With Ruling Span structures, post insulators have weight but no
geometric dimensions. Instead, you need to define the location of each insulator tip where the
conductor is attached. With Finite Element structure, post insulators have geometric dimensions,
as they are cantilevered from structure attachment points.
One of the reasons we have to include insulators as part of a structure top geometry, is that their
allowable swings or load angles are specific to the actual geometry of the structure to which the
insulators are attached .
Pole locations in traffic corridors are influenced by factors including traffic speed, traffic volume,
road deviation and traffic calming devices (roundabouts, chicanes, etc), embankments (cut or fill
slopes) next to the road, frangibility of the pole, road kerbing and parking.
Poles can be positioned closer to the road where there is a permanent barrier between the poles
and the road. Barriers can take the form of natural items such as kerbs, trees, rocks, and crash
barriers such as walls, wire rope, W-barrier, etc.
Frangible poles can typically be positioned closer to the road because they absorb the impact of
the vehicle to a greater extent than non-frangible poles.
Setback requirements will vary with the jurisdiction and various Codes of Practice exist at both
local and state government level. Supply Authorities should endeavor to work with relevant road
transport authorities, such as Councils, Shires and Main Roads Departments, to position poles in
mutually acceptable positions.
Guidance to setbacks and barriers is provided in :.
i)
AS/NZS 1158.1.3 Road Lighting - Vehicular Traffic (Category V) Lighting
Guide to Design, Installation, Operation and Maintenance
ii)
Austroads publications and guidelines for Rural and Urban Road Design.
iii)
AS/NZS 3845 Road Safety Barrier Systems.
Other pole location aspects are covered in Appendix
13.2 Railway and Tramway Crossings
Due to the potential for disruption to the community, for the installation and ongoing
maintenance, overhead power-lines that cross railways should be minimized where practical.
Crossings of railway and tramway tracks and property are subject to the requirements and
approval of the controlling authority. Special constructions, increased clearances and higher
safety factors generally apply in these areas. These conditions will vary with the jurisdiction and
should be ascertained prior to commencing the design layout.
Where railway power-lines crossings are required the installation should be designed to minimize
the impact of any future maintenance on the community. For example, the support conductor
structures and fittings should be of high integrity with a long life expectancy.
When designing railway crossing AS 4799 should be referred to in addition to requirements by
local rail authorities.
Navigable waterways that are traversed by overhead power lines must allow for the potential for
boat with masts and eliminate this risk of the masts coming in contact with the power lines.
Crossings of navigable waterways shall be designed in accordance with AS/NZS ????. The design
process includes liaison with the local maritime jurisdiction to ascertain likely vessel heights and
determination of maximum water levels prior to layout design in order to achieve the required
safety clearances. Guidance on appropriate signage and marking is also provided in AS/NZS ????
In order to better utilise service corridors and improve visual amenity joint use of infrastructure
with other utilities should be considered where it can be effectively implemented.
It is important to coordinate with nearby utility services to avoid both physical and electrical
interference. Overhead power-lines can electrically interfere with other utility services by
creating Earth Potential Rise (EPR) and Low Frequency Induction (LFI) hazards . EPR may
occur where high voltage earths are installed in the vicinity of these services. LFI can occur
where overhead power lines are run in parallel and in close proximity with utillity services that
are conductive (ie oil, gas and water pipelines, telecommunications equipment and road control
equipment).
Prior to commencement of line construction, arrangements should be made with the relevant
utilities to locate assets (in order to avoid damage during construction) and coordinate joint use
arrangements where agreed.
Particular consideration should be given to step and touch potentials and induced voltages
associated with the line which could impact on the operation of other services.
Publications relevant to the coordination of power and telecommunication circuits include :
AS/NZS 3835.1 Earth Potential Rise Code of practice
AS/NZS 3835.2 Earth Potential Rise Application Guide
SAA HB 219 Earth Potential Rise Worked Examples
SAA HB 87 Joint Use of Poles
SAA HB 88 Unbalanced High Voltage Power Lines Code of Practice
SAA HB 100 Safe Working Practices
SAA HB 101 Low Frequency Induction Code of Practice
SAA HB 102 Low Frequency Induction Application Guide
SAA HB 103 Crossings Code of Practice
CJC 4 - Coordination of power and telecommunications standard
13.5 Aerial Lines in the Vicinity of Aircraft
Where overhead lines are located neat takeoff and landing areas for aircraft, special precautions
need to be considered in the overhead design process. A coverage of the obstacle limitation
surfaces (OLS), final approach and takeoff (FATO) areas and marking of the overhead line are
given in Appendix ..
13.6 Rural Activities in Proximity to Line
The layout design process should identify activities which are likely to occur in proximity to the
line and which might impact on the safe and reliable operation of the line. Risk assessment should
be undertaken and risk treatments applied to ensure that the residual risk is acceptable to the
organization.
It may be necessary to place restrictions on activities which might impact on line reliability
(including those involving high machinery, propagation of trees or irrigation under or near the
line) or to design for additional clearances to accommodate them. Where possible a line route
should be selected which avoids areas where they are likely to be affected by such activities.
Where usage of land is such that it is reasonable to expect that agricultural activities involving the
handling, movement or storage of large lengths of conductive material, take place or may take
place, the positioning of structures may need to be considered to minimise the risk of contact.
design layouts that position structures away from regular agricultural activities eg:
along fence lines instead of across paddocks.
away from material and equipment storage areas
away from vehicle, machinery and plant storage areas
the use of underground cables and covered conductor
underground services
designs that achieve maximum practical clearances
Where there is a significant bushfire risk designers may need to take precautions to ensure that
there is low risk of conductor clashing such as increased conductor separation, use of covered or
insulated conductors and mid span spacers.
In areas of sensitive vegetation, covered or insulated conductors may be considered to reduce the
environmental impact
L
L
L RS
Where:
< 150 kV
150 300 kV
Single circuit
Double circuit
Single circuit
Double circuit
Matr. Erec Total Matr. Erec Total Matr. Erec Total Matr. Erec Total
Conductors
Earthwires
Insulators
/fittings
Towers
Foundation
Right
of
way,
Engineering
Totals
20.2
11.4
31.6
25.0
11.5
36.5
20.7
12.0
32.7
27.0
11.5
38.5
2.4
1.7
4.1
1.5
1.1
2.6
2.1
1.6
3.7
1.3
1.2
2.5
5.2
3.5
8.7
6.5
3.5
10.0
6.5
2.4
8.9
5.0
3.0
8.0
21.9
11.2
33.1
21.0
9.4
30.4
21.0
11.8
32.8
21.5
9.8
31.3
11.5
5.0
16.5
11.5
5.0
16.5
11.2
5.4
16.6
10.7
5.5
16.2
3.0
3.0
6.0
2.0
2.0
4.0
2.5
2.8
5.3
1.5
2.0
3.5
64.2
35.8
100.0
67.5
32.5
100.0
64.0
36.0
100.0
67.0
33.0
100.0
Errant Vehicles
Pole set backs are influenced by factors including, traffic speed, traffic volume, road
deviation and traffic calming devices (roundabouts, chicanes, etc), embankments (cut or fill
slopes) next to the road, frangibility of the pole, road kerbing and parking.
Poles can be positioned closer to the road where there is a permanent barrier between the
poles and the road. Barriers can take the form of natural items such as kerbs, trees, rocks,
and manmade crash barriers such as walls, wire rope, W-barrier, etc.
The poles should be positioned behind the man made crash barriers to be outside the deflective
zone of the barrier.
Frangible poles can typically be positioned closer to the road because they absorb the
impact of the vehicle to a greater extent than non-frangible poles.
shopping centres, major entrances/ exits to sporting or entertainment venues, and train or bus
stations entrances/ exits, .
15.5 Markers
Conductors and structures in locations susceptible to bird strike or inadvertent contact in the
vicinity of the line can be marked to improve their visibility and reduce the risk of contact.
Marking may take the form of reflective or brightly coloured discs, flags or marker balls attached
to the cables or structures. Care should be taken to ensure that markers do not compromise circuit
clearances and overload structures.
Permanent Markers
The fitting of permanent makers is the responsibility of the line owner. Permanent makers may
be in the form of spheres attached to the conductors as described AS3891.
Where spheres are used, account must be taken of their weight and resistance to wind when
determining swing, sag and tension. In simple cases the performance of the conductor may be
determined by approximating the point load of the sphere to a distributed load but software
packages, which more accurately reflect actual condition, are available and should be used where
practicable.
Temporary Markers
Where aircraft operations such as crop dusting are carried out in the vicinity of overhead lines it is
the responsibility of the aircraft operator to mark the location and direction of the lines. Such
markers may be attached to the conductors or supports (subject to approval of the line owner) or
placed on the ground in the vicinity of the overhead line.
16 VEGETATION CLEARANCES
There are situations where there are conflicts with Trees and Powerlines. Trees, shrubs and other
vegetation enhance our lifestyles by providing shade and privacy around our homes, offer a
habitat for birds and wildlife, and add aesthetic value to our gardens. However, vegetation
interfering with powerlines is a proven risk to public safety, the environment and one of the main
causes of power supply problems.
Vegetation Management Principles
The basis for undertaking vegetation clearing is covered in the following principles:
Recognise that there are sites with vegetation of significance located near powerlines
requiring special consideration and treatment because of their importance to the
community and the environment.
When selecting line routes, establish the most economical, technically acceptable option,
taking into account the ongoing costs of vegetation management, the objectives of
environmental policy, and maintenance of the overhead network.
Regrowth Zone - is a space beyond the clearance zone that must be trimmed so that the
regrowth does not enter the clearance zone within the trimming cycle
Risk Management Zone - is a space in which trees or limbs may pose a risk in adverse
weather conditions due to factors such as instability and weakness. Clearance in this zone
is discretionary.
Low Growth Zone - is the space below the clearance zone where vegetation is allowed
which will not have a height of more than a specified distance, depending on the
circumstance
Typical clearance distances for low voltage Aerial Bundled Cable and Insulated Service Cable are
shown in Table 2.
PLS Tower
PLS Pole
MS Tower
Microstran
SpaceGass
I Tower
Catan
TL Pro
Livewire
Poles and Wires
Layout Programs:
PLS Cadd
Catan
TL Pro
Livewire
Poles and Wires
SagTen
Geotechnical Programs:
PLS Caisson
Brinch Hanson Foundation Package
Livewire
Electrical Programs:
EMTP
CDEGS
IEEE Flash 1.8
Sigma SLP
18
Clause B1 - Australia
The provisions in this clause are a major departure from the previous Cb1 and AS/NZS 1170.2 in the
definition of wind regions. It acknowledges that most wind damage in Australia and New Zealand to the
overhead line networks occur during severe thunderstorms and provides a more reasonable interpretation
of wind regions based performance of overhead line networks over a number of years.
Figure B 1
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. This contrasts to the multiple narrow 50km wide zones in AS/NZS 1170.2 for the near coastal
areas. Wind velocities are selected from AS/NZS 1170.2 as appropriate to the security level selected for
the relevant location and wind zone required in the standard Figure B1.
This leaves some latitude to the designer to select the V50 value for a selected Security Level as required in
Section 6 of the standard.
For example in Zone 1 for Australia where cyclonic events occur AS/NZS 1170.2 provides for wind zones
C, D and B. Recent experience suggests that these arbitrary 50km zones are not relevant to severe
Category 4 and Category 5 cyclonic events as the storm damage paths have been observed to extend
100km inland over a width of some 20km. In these cases it would be appropriate to select a V50 value from
region C
For the remainder of the non cyclonic regions within Zone 1 such as New South Wales coastal area only
one V50 value is provided but a higher return period value may be adopted in some local areas where
regular storm damage occurs.
For example in the coastal area immediately north of Sydney or the south east Queensland regions it might
be prudent to adopt a V100 value or a higher security level as appropriate, in view of the relatively high
frequency of severe thunderstorms.
It should be noted that the selection of the regional wind speed is relevant to the lines location, and care
needs to be exercised where standard designs are applied to multiple sites. Where an overhead line is of
significant length, variations in wind loading may be required as the line passes through differing wind
exposure situations.
For example a line emanating from a coastal substation in a cyclonic region passing inland over a coastal
range to an inland supply point could pass through three significant design wind climates that should be
incorporated in the line design.
B2 New Zealand
Apart from the probability in some areas of turbulent effects near large mountains the majority of New
Zealand is within Region A7 of AS/NZS 1170.2. Some caution needs to be applied to locations on hills in
close proximity to sea coasts.
B3 Synoptic wind regions
Downdraft winds are the predominate wind that governs the design of overhead lines in Australia with the
exception of cyclonic coastal regions. The wind velocities provided in AS/NZS 1170.2 include this type of
event.
The important aspect that is different is the span reduction factor when compared to that applicable to the
larger scale synoptic wind gust events. Downdraft wind gusts are relatively narrow and when they strike
the ground observations of vegetation damage suggests a burst swath varying from 100m up to 1000m in
width being common occurrences during more severe thunderstorms and hence the wind can envelop one
or more spans simultaneously.
The standard provides a Span Reduction Factor (SRF) to be applied as provided in Figure B 6
Terrain -Height Multiplier Mz,cat for the common range of structure in open terrain and heights < 50m is
1.0
B4.2 Tornadoes
The standard identifies that these events do occur in some parts of the country but that they are relatively
rare random events and of low intensity < F2 strength when compared to those in United States of America
and Argentina. Unless a line has a very high security requirement it is recommended that no special
loadings be generally considered.
B5. Wind Pressures
For distribution overhead lines a simplified approach to wind loadings can be applied
particularly as most lines are located in Category 3 or Category 4 exposure and significant
shielding from vegetation and structures occurs.
The basic regional wind pressure (pb ) as selected from Table E1 below for the relevant wind region
from AS1170.2 and limit-state being considered and ps and p u represent the corresponding basic
pressures for the serviceability and strength limit-states, respectively.TABLE E1
BASIC REGIONAL PRESSURES
Country
New Zealand
Australia
P s (2)
0.7
0.7
p u (2)
1.2
1.4
A
B
0.9
0.9
1.5
2.2
NOTES:
1 Geographic regions are shown separately for New Zealand and Australia, the symbols for each region being
those given in the respective wind-load Standards.
2 The basic regional wind speeds, from which the basic pressures are derived, do not differ greatly from one
region to the next in New Zealand. To simplify this, the regions have been grouped around two values, namely
45 m/s and 48 m/s.
The standard provides detailed guidance on the derivation of wind loadings on structures. An important
issue to consider is the angle of incident of the wind. Studies have shown that for a square based tower an
angle of incidence of 22.5 degrees to the plane at right angles to the direction of the line will be critical for
the design of main tower leg members.
Drag factors for a range of Solidity Ratios are provided in Table B2. Care needs to be taken in calculation
of these rations to ensure adequate allowance is made for connection gusset plates and actual member sizes
used, particularly on compact tower superstructures and beams on horizontal configuration single circuit
towers.
The Span Reduction Factor for each wind climate region is a significant issue for design of structures. In
Wind Zone 1 and Zone 111 the designer needs to consider both downdraft SRF as well as synoptic SRF
although the downdraft will be found to be the controlling condition.
In Zone 11, only downdraft conditions apply and is significant in the design of distribution pole lines
where average spanning will be typically in the 50 -300m range. In these cases a SRF of 1.0 is required.
B5.4 Wind forces on insulators and fittings
While this is standard design consideration allowance needs to be made for any other devices and
apparatus that may be provided on conductors. Item such as aerial markers at regular intervals along a
conductor or earthwire spans near feeder and waterway crossings and airports, temperature transponders,
and surge arrestors, need to be considered. Retrospective installation or aerial markers may justify design
checks particularly where placed on earthwires.
B6 Topographical Effects
This is an informative section of Appendix B and is based on localised performance of lines over time, and
these details provide application guidelines to be considered during the line layout process in particular to
minimise potential risks of wind overload due to topographical influences. In locations where a structure
position cannot be relocated to avoid a high risk situation then a higher duty/strength structure is usually
the simplest option.
TABLE D1
ABOVE-GROUND ENVIRONMENTAL EXPOSURE CLASSIFICATION (AUSTRALIA)
Climatic zone
(see Figure D1)
Arid
Temperate (4)
Tropical
Non-industrial
A1
Industrial
Non-industrial
B1
B1
B2
A2
Industrial
Non-industrial
B1
B1
B2
B1
Industrial
B2
B1
B2
(See Note 4)
Any
TABLE D2
SUGGESTED RANGE OF NOMINAL SERVICE LIFE OF
STEEL STRUCTURES AND CONCRETE POLES
Suggested nominal service life (years)
Galvanized steel(5)
Exposure class
200 g/m
2(1)
400 g/m
Concrete
2(1)
600 g/m
2(1)
C (2)
A1
60100+
100+
100++
100+
A2
2560
60100
75100+
80100
B1
1225
2550
3575
6080
B2
825
1550
3575
5060
( 3)
312
(6)
625
(6)
935
(6)
50
(4)
TABLE D4
SUGGESTED RANGE OF NOMINAL SERVICE LIFE OF
TIMBER POLES
Zone
(see
Figure D3)
Class 1
4555
Class 2
3545
Class 3
2535
Class 4
4050
Class 1
2535
Class 2
1525
50+
50+
3040
50+
3040
2535
50+
50+
4050
50+
50+
3040
These service life expectancies are indicative ranges and should be used in conjunction with
local service experience and exposure in order provide a basis for design.
TABLE G1 (continued)
Clause F1
General
This clause sets out the design properties and design methods for timber poles and components in
accordance with AS 1720.1 or NZS 3606.
Clause F1.2 Characteristic strengths and elastic moduli
Strength groups for timber poles are as given in AS 2878 and as summarised below. Those in
parenthesis have provisional status as specified in AS 2878.
TABLE G1
TIMBER SPECIES, STRENGTH GROUPS, NATURAL DURABILITY RATINGS AND
BRAND MARKS
Standard trade common name
Species
brand
S1
CB
gum, grey
S1
GG
S1
BU
ironbark, grey
S1
GI
blackbutt
S2
BB
box, grey
S2
1*
GB
box, white
(S2)
2*
WX
S2
2*
WT
gum, poplar
(S2)
3*
PG
gum, salmon
(S2)
3*
SA
gum, spotted
S2
SG
S2
NI
ironbark, red
S2
RI
mahogany, red
(S2)
RM
mahogany, southern
S2
SM
mahogany, white
S2
WM
stringybark, blue-leaved
S2
3*
SL
stringybark, silvertop
S2
SS
Tallowwood
S2
TW
ash, silvertop
S3
ST
S3
NA
bloodwood, brown
S3
2*
BD
(Continued)
S3
1*
Species
brand
RW
box, brush
S3
BH
box, red
S3
2*
RX
box, yellow
S3
YB
S3
BG
S3
FR
gum, Maiden's
S3
3*
MG
S3
MT
gum, rose
S3
RO
S3
3*
SY
S3
BT
satinay
S3
stringybark, brown
S3
BS
stringybark, messmate
S3
MS
stringybark, red
S3
RS
stringybark, white
S3
WS
stringybark, yellow
S3
YS
turpentine
S3
TP
ash, alpine
S4
AA
ash, mountain
S4
MA
brownbarrel
S4
BL
gum, manna
S4
MN
gum, mountain
S4
MO
gum, yellow
(S4)
YG
peppermint, narrow-leaved
S4
NL
peppermint, Sydney
(S4)
SP
RR
S5
peppermint, black
(S5)
3*
BP
S5
1*
WC
pine, slash
S5
PS
S5
DF
S6
DF
pine, Caribbean
(S6)
PB
pine, hoop
S6
HP
pine, loblolly
S6
PL
pine, maritime
(S6)
PM
pine, radiata
S6
PR
pine Corsican
(S7)
4*
PC
(Continued)
(S7)
pine, ponderosa
pine, long-leaf
Species
brand
4*
PP
(<S7)
4*
PW
4*
PI
4*
PF
* These durability ratings are not listed in AS 5604 and have been assigned the classification in AS 2209.
NOTES:
1
The strength groups assigned in the above table are those given in AS 2878 for unseasoned timber.
Provisional strength groups are shown in brackets. These are assigned in those cases where the evidence
was inadequate to allow positive grouping at the time AS 2878 was published.
For information on species not listed refer to CSIRO, Forest Products or state forestry authorities.
The characteristic strengths and elastic moduli for untrimmed poles that conform in quality to the
grade requirements specified in AS 2209 are as specified in Tables F.3.1 and F.3.2, unless verified
by testing of samples from the same grade.
Strength groups and joint group classifications are assigned to species in accordance with
AS 1720.2.
TABLE F.3.1
POLE TIMBERS GRADED TO AS 2209 RELATIONSHIP BETWEEN STRENGTH
GROUPS AND CHARACTERISTIC PROPERTIES (MPa)
Strength
group
Stress
grade
Bending
(f b )(3)
S1
S2
S3
S4
S5
S6
S7
F34
F27
F22
F17
F14
F11
F8
100
80
65
50
40
35
25
Tension parallel to
grain (f t )(3)
Hardwood
Softwood
60
50
40
30
25
20
15
26
21
17
13
Shear
(f s ) (3)
Compression
parallel to
grain (f c ) (3)
7.2
6.1
5.0
4.3
3.7
3.1
2.5
75
60
50
40
30
25
20
Short
duration
modulus of
elasticity (E)
21500
18500
16000
14000
12000
10500
9100
F2 Design Capacity
Using the design method set out in the standard and timber pole characteristic properties as indicated
above, the following design bending strength capacities result for each strength group and assumed ground
line pole diameter.
It should be noted that the maximum bending moment will occur at a point around 200 mm below ground
level in average soil backfill conditions. This is due to several factors. Clayey soils will shrink away from
the pole as they dry out; the sub soil requires some distance to provide fixity to develop restraint, and
significant degradation in the zone 300mm below ground surface level will occur over time. In deep
cracking/ reactive clays this 200mm allowance could be deeper unless breast logs or stabilized backfill is
used.
Assumed
tip loading
position
Tip
dt
hr
Ground level
200mm
dg
db
Butt
TABLE F4.1
ULTIMATE BENDING STRENGTH AT GROUND LINE
PRESSURE IMPREGNATED NATURAL ROUND HARDWOOD POLES
(kNm)
Strength group
S1
S2
S3
S4
S5
S6
Pole diameter at GL
(mm)
100
80
65
50
40
35
150
25.3
20.3
16.5
12.7
10.1
8.9
175
40.3
32.2
26.2
20.1
16.1
14.1
200
60.1
48.1
39.1
30.0
24.0
21.0
225
85.5
68.4
55.6
42.8
34.2
29.9
250
117.3
93.9
76.3
58.7
46.9
41.1
275
156.2
125.0
101.5
78.1
62.5
54.7
300
202.8
162.2
131.8
101.4
81.1
71.0
325
257.8
206.3
167.6
128.9
103.1
90.2
350
322.0
257.6
209.3
161.0
128.8
112.7
375
396.1
316.8
257.4
198.0
158.4
138.6
400
480.7
384.5
312.4
240.3
192.3
168.2
425
576.5
461.2
374.7
288.3
230.6
201.8
450
684.4
547.5
444.8
342.2
273.8
239.5
475
804.9
643.9
523.2
402.5
322.0
281.7
500
938.8
751.0
610.2
469.4
375.5
328.6
550
1249.5
999.6
812.2
624.8
499.8
437.3
600
1622.2
1297.8
1054.5
811.1
648.9
567.8
k 20 immaturity factor applied for poles of diameter less than 200 mm.
k 21 = 1.00, shaving factor (in critical zone, i.e., 1 m < GL < +2 m).
k d = 1.00, preservative treated Eucalypt, 25 year expected maintenance free service life.
TABLE F4.2
ULTIMATE BENDING STRENGTH AT GROUND LINE
UNTREATED, SHAVED/UNPROCESSED HARDWOOD POLES
(kNm)
Strength group
S1
S2
S3
S4
S5
S6
Pole diameter at GL
(mm)
100
80
65
50
150
20.3
16.2
13.2
10.1
8.1
7.1
175
32.2
25.8
20.9
16.1
12.9
11.3
200
48.1
38.5
31.2
24.0
19.2
16.8
225
68.4
54.8
44.5
34.2
27.4
24.0
250
93.9
75.1
61.0
46.9
37.6
32.9
275
125.0
100.0
81.2
62.5
50.0
43.7
300
162.2
129.8
105.4
81.1
64.9
56.8
325
206.3
165.0
134.1
103.1
82.5
72.2
350
257.6
206.1
167.4
128.8
103.0
90.2
375
316.8
253.5
205.9
158.4
126.7
110.9
400
384.5
307.6
249.9
192.3
153.8
134.6
425
461.2
369.0
299.8
230.6
184.5
161.4
450
547.5
438.0
355.9
273.8
219.0
191.6
475
643.9
515.1
418.5
322.0
257.6
225.4
500
751.0
600.8
488.2
375.5
300.4
262.9
35
550
999.6
799.7
649.8
499.8
399.9
349.9
600
1297.8
1038.2
843.6
648.9
519.1
454.2
NOTES:
1
k 20 immaturity factor applied for poles of diameter less than 200 mm.
k 21 = 0.85, shaving factor (in critical zone, i.e., 1 m < GL < +2 m).
k 22 = 1.00, no processing.
k d = 0.80, preservative treated Eucalypt, 25 year expected maintenance free service life.
TABLE F4.3
ULTIMATE BENDING STRENGTH AT GROUND LINE
PRESSURE IMPREGNATED, SHAVED SOFTWOOD POLES
(kNm)
Strength group
S1
S2
S3
S4
S5
S6
Pole diameter at GL
(mm)
100
80
65
50
40
35
150
18.3
14.7
11.9
9.2
7.3
6.4
175
30.8
24.6
20.0
15.4
12.3
10.8
200
51.1
40.9
33.2
25.5
20.4
17.9
225
72.7
58.2
47.3
36.4
29.1
25.5
250
99.7
79.8
64.8
49.9
39.9
34.9
275
132.8
106.2
86.3
66.4
53.1
46.5
300
172.4
137.9
112.0
86.2
68.9
60.3
325
219.1
175.3
142.4
109.6
87.7
76.7
350
273.7
219.0
177.9
136.9
109.5
95.8
375
336.6
269.3
218.8
168.3
134.7
117.8
400
408.6
326.9
265.6
204.3
163.4
143.0
425
490.1
392.0
318.5
245.0
196.0
171.5
450
581.7
465.4
378.1
290.9
232.7
203.6
475
684.2
547.3
444.7
342.1
273.7
239.5
500
798.0
638.4
518.7
399.0
319.2
279.3
550
1062.1
849.7
690.4
531.1
424.8
371.7
600
1378.9
1103.1
896.3
689.5
551.6
482.6
NOTES:
1
k 20 immaturity factor applied for poles of diameter less than 200 mm.
k d = 1.00, preservative treated Eucalypt, 25 year expected maintenance free service life.
Width <0.3 mm
(2)
Width <0.2 mm
(3)
Width <0.1 mm
Exposure Classification C.
The crack width limit of 0.25mm is therefore set to provide a conservative but important
serviceability standard for concrete poles. In more severe exposure sites (Classification C
particularly) other design considerations need to be taken as set out in Appendix D.
Concrete cover is the other important consideration for providing concrete durability.
Clause I 5 Concrete Cover - sets out minimum cover requirements for varying exposure conditions,
reinforcing bar, concrete aggregate sizes and water absorption limits.
With the high characteristic compressive strengths that can be achieve through mix design, concrete
compaction (particularly by centrifugal spinning), the provision of high and consistent standards of
initial concrete curing will greatly enhance long and durable service life of pole elements.
Water absorption testing (Appendix O) on prototype pole is essential where concrete cover of 19mm
and less is provided. Keep in mind that with all dimensions there must be an acceptance tolerance
and +/- 2mm is sometimes difficult to achieve during high mechanical compaction of concrete and
it is more than likely that at some locations on a pole element it could result in tolerances of
+/- 3mm occurring.
ie 19mm nominal cover could be reduced to possibly 15mm and durability then becomes a
significant issue. This means that if concrete cover is expected to be on dimensional tolerance limit
or greater, then additional effort needs to be placed on the curing process once the pole product is
stripped from the moulds.
As an example there is some standard prestressed concrete pole products produced in Japan that
have characteristic strength of typically 60MPa and 9 mm cover over tendons and they are cured by
full immersion in water for 10 days.
Service experience in Europe with some of the earliest centrifugally spun poles has shown that even
in cold climates with ice and snow exposure that there are some poles still in excellent service
condition after over 90 years.
Testing of Concrete Poles
Clause 8.5.2 of the Standard sets out Load Testing requirements for pole type structures. Where
large volumes of similar type/length /strength poles are in mass production these tests form a very
important check on design and consistency of manufacturing standards
Prototype testing is the most important test in ensuring flexural and shear strength characteristics of
any pole and it is important in these tests to model the design loading assumptions as close as
possible.
P-delta (load/deflection) considerations are very important for concrete pole testing due to their
inherent flexibility, and if load tests are carried out in the horizontal mode then additional loading
in the longitudinal plane should be considered in order to reflect deflected vertical self weight mass
eccentric loading stresses.
Vertical prototype load tests if possible, are preferred to enable realistically model loading
characteristics, but should also be accompanied by a horizontal test if horizontal routine testing is
carried out, so that a comparative base line test deflection characteristic is established for
production control through further routine sample tests.
Crack development during load testing must be carefully monitored and significant or accelerated
crack width development with small load increase could signify structural design weakness at loads
below 50% of ultimate capacity.
Cracks in non prestressed poles above 40% load capacity most likely will not close up after release
of load on test, however if the pole were to experience this level of loading in service, the self
weight load will most likely close resultant cracks.
It should be noted that the advantage of prestressing and partial prestressing tendons in pole designs
provides control of cracking under all normal service loading conditions likely to be experienced.
It is most important in the production control for concrete pole manufacture to not only ensure
consistency of the concrete mix but also in the measured volume of concrete batched and added to
the moulds to ensure design wall thickness is provided. In spun poles the internal wall can have in
part minimum fines in the surface zone and hence durability of the internal concrete may need to be
enhanced by sealing off the butt to prevent ground water ingress.
If the total internal void in circular concrete poles is sealed off top and bottom and with through
tubes for bolting, significant thermal differentials from air temperature variations during the day
will cause pressure variations internally and can cause ground water to be pumped inside the void if
any below ground opening exists.
Butt sealing of hollow poles is recommended for most applications, particularly where high ground
water tables are known to exist, or can be expected to occur after seasonal rainfall.
Handling Stresses
While the standard does not cover the area of handling stresses, the normal approach adopted is for
construction and transport induced stresses be restricted to be less than normal design stresses.
However on cross country lines, particularly in through difficult terrain and where longer pole
elements are used, transport and handling stresses can result in pole damage can easily occur. On
such line projects, flexural stresses from off road transporters, possible snigging along the ground at
very difficult sites, and lifting /erection stresses, need to be included as a specific design loading
case.
L1
GENERAL PRINCIPLES
While this is an informative appendix in the standard it establishes some important principles for
acceptable design methods associated with overhead line footings and their foundations.
While several alternative approaches can be used for the design of footings and the interpretation of the
foundation conditions, the designer should exercise sound engineering judgment in determining which
method is most appropriate for the standard of construction required.
When designing overhead line foundations, the designer also has the option to design each footing for sitespecific loadings and actual subsurface conditions or to develop standard designs that can be used at sites
within application guidelines for various possible sub soil conditions.
Reference is also made in the standard to relevant references for design methods such as IEEE Std 6912001 Guide for Transmission Structure Foundation Design and Testing.
Reference could also be made to American Society of Agricultural Engineers ANSI/ASAE EP486.1 OCT
00 Shallow Post Foundation Design for distribution pole structure footing design.
L2 GEOTECHNICAL PARAMETERS OF SOILS AND ROCKS
The standard provides some typical detailed information on a range of soil types that may be encountered
on any overhead line in Tables L1 L4.
On major transmission lines it can be expected that a higher level of specialist engineering will be applied
to the geotechnical design of footings and their foundations and hence some form of subsurface
investigation could be expected to be carried out along the easement of transmission lines, to obtain
geotechnical parameters required to design the transmission structure footings. However this may not
always be practical and some simplified assessments may be required to establish some indicative yet
conservative parameters. Table L4 can be used in the absence of more detailed site information as a
conservative guide. The values in Table L4 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 for a particular region or site.
The method that is adopted for design and the application of assumed soil properties , must take into
consideration the expertise and experience of the on site construction supervisor, boring machine operator
and any full time network owner inspector utilised on site.
In distribution line construction simple subsurface application design guidelines are commonly applied,
except for the heavier steel or concrete pole construction sometimes used on special aesthetic lines and sub
transmission type lines. In the later case a higher level of engineering design usually can be expected.
This design method utilizes two soil assumptions. First, it is assumed that the soil resistance to deformation
is proportional to displacement for the range of deformations used in design. Secondly, it is assumed that the
resistance to deformation increases linearly with depth below the ground surface. This increasing resistance
to deformation is due to the confining pressure of the soil overburden. For each case, the maximum soil
pressure is limited to the allowable lateral pressure.
8Ma
d
Sb
6Va +
Where d =
2. Empirical Design Formula This method is based purely on the height above ground for a given pole diameter at ground level
and has no direct relationship with the loads applied to the pole.
Assumed
tip loading
position
Tip
dt
h
r
Ground level
200mm
dg
db
Butt
The embedment lengths LGL are based on a simplified method, as defined in Equations E1
and E2 and relate purely to pole height above ground hr .
For poles where the height from the ground line (GL) to the conductors is less than 18 m,
the embedment length is calculated by Equation E1, with a maximum of 3.6 m. For longer
poles, up to 21 m in height, the embedment length is calculated by Equation E2, with a
maximum of 4.8 m.
Equations E1 and E2 are specified as follows:
L GL = Min[(1 + 0.1 h r) (d g/250),3.6] for h r <18
. . . E1
. . . E2
where
L GL = min. embedment depth, in metres
hr
Table EI gives numerical values for the planting depths for the common range of pole
dimensions.
TABLE E1
MINIMUM EMBEDMENT DEPTH LGL (m)
Height from GL (ground line) to conductor (m)
Pole dia. at
GL (mm)
7.5
10.5
12
13.5
15
16.5
18
150
1.0
1.1
1.1
1.2
1.3
1.4
1.5
1.6
1.3
175
1.1
1.2
1.3
1.4
1.5
1.6
1.8
1.9
1.5
200
1.3
1.4
1.5
1.6
1.8
1.9
2.0
2.1
1.7
225
1.4
1.6
1.7
1.8
2.0
2.1
2.3
2.4
1.9
250
1.6
1.8
1.9
2.1
2.2
2.4
2.5
2.7
2.1
275
1.8
1.9
2.1
2.3
2.4
2.6
2.8
2.9
2.3
300
1.9
2.1
2.3
2.5
2.6
2.8
3.0
3.2
2.5
325
2.1
2.3
2.5
2.7
2.9
3.1
3.3
3.4
2.8
350
2.2
2.5
2.7
2.9
3.1
3.3
3.5
3.6
3.0
375
2.4
2.6
2.9
3.1
3.3
3.5
3.6
3.6
3.2
400
2.6
2.8
3.0
3.3
3.5
3.6
3.6
3.6
3.4
425
2.7
3.0
3.2
3.5
3.6
3.6
3.6
3.6
3.6
450
2.9
3.2
3.4
3.6
3.6
3.6
3.6
3.6
3.8
475
3.0
3.3
3.6
3.6
3.6
3.6
3.6
3.6
4.0
500
3.2
3.5
3.6
3.6
3.6
3.6
3.6
3.6
4.2
550
3.5
3.6
3.6
3.6
3.6
3.6
3.6
3.6
4.7
600
3.6
3.6
3.6
3.6
3.6
3.6
3.6
3.6
4.8
embedment
the vertical distribution of bearing pressure above the centre of rotation is in the form of
symmetrical parabola with its axis of symmetry located at one third of the embedment
depth below the ground surface with its maximum value taken as 1.5 f b; and
the vertical distribution of the bearing pressure below the centre of rotation is a skewed
parabola for which the resultant horizontal reaction force is located at eight ninths of the
embedment depth below ground level. The method relies primarily on varying the
embedment depth and its projected area to engage the required resistance of the foundation
to overturning and sliding
3.1
FOUNDATION PROPERTIES
TABLE I1
BEARING STRENGTH OF SOILS AT THE SERVICEABILITY LIMIT STATE
Class
Very soft
Soil description
Soft
Strength (f b ) kPa
Firm
Very firm
Hard
Gravels; dry
clays
240 < f b
NOTE:
D=
. . . I3.2(1)
where
C
fbu
1.5fb
HR .h r
HR
hr
Embedment support is most commonly achieved by boring an oversize hole to the required
depth and after installing the pole, backfilling the space between the pole and the perimeter
of the hole. Hence the nature and condition of the backfilling material becomes an
important consideration in the choice of an appropriate value for the parameter b.
The following are recommended:
(i)
If the backfill is properly prepared concrete, b may be taken as the diameter of the
bored hole.
(ii)
If the backfill is the excavated material, b should be taken as the diameter of the pole
and, unless full recompaction of the fill can be assured, the value of fb should be
reduced from its undisturbed value.
(iii) If the backfill is cement-stabilized soil, b may be taken as the mean value of the
diameters of the pole and the bored hole.
The physical representation of the assumptions and the relevant equation parameters are
illustrated in Figure I3.1. The derivation of the equation is given in Paragraph I4 of this
Appendix.
For poles, particularly guyed or stayed poles, the minimum plan area of the footing required
at its lowest extremity (Afb ) is calculated from the following equation:
Afb = ( Fv + Fgt ) / f b
where
Fgt
Fv
the sum of the vertical forces acting on the pole from loads other than F gt
(a)
Based on the above assumptions, the reaction force on upper bearer (Rb1) is given by
. . . I3.3(1)
. . . I3.3(2)
Ab = Rb / 0.85 f bu
. . . I3.3(3)
i.e. HR + R2 R1 = 0
Reaction R1 =
4
D
= b f bu .
3
3
4 b f bu D
9
2
The sum of the moments about any point in the vertical plane
containing H R and the reactions is zero. Taking moments about the
line of action of R 2
. . . I4(1)
9 H R hr + 8 H R D 5 D
(4b. f bu .D)
=0
9
. . . I4(2)
b. f bu .D 2 3.6 H R D 4.05 H R hr = 0
which is a simple quadratic of the form ax2 + bx + c = 0
Solving for D
D = 3.6 H R +
12.96( H R )2 + 16.2. b. f bu .H R . hr
2b. f bu
. . . I4(3)
. . . I4(4)
Table I2 has been prepared from Equation I4(3) for an fb value of 150 kPa and various
values of H, b and h r. Note that the tabulated depths include the additional 0.2 m to allow
for soil shrinkage in the ground line zone. As can be seen from the equation, linear
interpolation or extrapolation cannot be used for values different from those tabulated;
however, the tabulated values will be conservative for foundation materials with fb greater
than 150 kPa but should not be taken as less than 0.5 m.
Embedment depths for materials with a bearing strength less than 150 kPa should be
calculated directly from Equation I4(3), to which a further 0.2 m has to be added. Practical
considerations of foundation materials and available excavating equipment will determine
which combination of hole diameter and embedment depth that will be economically viable
at each location.
TABLE I2(A)
H = 1.5
H = 3.0
H = 6.0
H = 10
b=0.3
0.45
0.60
0.30
0.45
0.60
0.3
0.45
0.6
0.75
0.9
0.3
0.45
0.6
0.75
0.9
3.0
0.8
0.7
0.6
1.0
0.9
0.8
1.4
1.2
1.0
0.9
0.9
1.8
1.5
1.3
1.2
1.1
4.5
0.9
0.7
0.7
1.2
1.0
0.9
1.6
1.4
1.2
1.1
1.0
2.1
1.7
1.5
1.4
1.2
6.0
1.0
0.8
0.7
1.3
1.1
1.0
1.8
1.5
1.3
1.2
1.1
2.4
1.9
1.7
1.5
1.4
7.5
1.1
0.9
0.8
1.4
1.2
1.1
2.0
1.7
1.4
1.3
1.2
2.6
2.1
1.8
1.7
1.5
9.0
1.1
1.0
0.9
1.6
1.3
1.1
2.2
1.8
1.6
1.4
1.3
2.8
2.3
2.0
1.8
1.6
10.5
1.2
1.0
0.9
1.7
1.4
1.2
2.3
1.9
1.7
1.5
1.4
3.0
2.4
2.1
1.9
1.7
12.0
1.3
1.1
1.0
1.8
1.5
1.3
2.4
2.0
1.8
1.6
1.5
3.2
2.6
2.2
2.0
1.8
13.5
1.3
1.1
1.0
1.8
1.5
1.3
2.6
2.1
1.8
1.7
1.5
3.3
2.7
2.4
2.1
1.9
15.0
1.4
1.2
1.0
1.9
1.6
1.4
2.7
2.2
1.9
1.7
1.6
3.5
2.8
2.4
2.2
2.0
16.5
1.5
1.2
1.1
2.0
1.7
1.5
2.8
2.3
2.0
1.8
1.7
3.6
3.0
2.6
2.3
2.1
18.0
1.5
1.3
1.1
2.1
1.7
1.5
2.9
2.4
2.1
1.9
1.7
3.8
3.1
2.7
2.4
2.2
19.5
1.6
1.3
1.2
2.2
1.8
1.6
3.0
2.5
2.2
1.9
1.8
3.9
3.2
2.8
2.5
2.3
22.0
1.6
1.4
1.2
2.3
1.9
1.6
3.2
2.6
2.3
2.1
1.9
4.1
3.4
2.9
2.6
2.4
NOTES:
1
Tabulated depths include the 0.2 m additional depth required by Clause 6.4
The embedment depth should be not less than 0.5 m in any soil.
TABLE I2(B)
POLE EMBEDMENT DEPTHS FOR SOILS WITH f b = 150 kPa
Effective
height h
(m)
H = 24
H = 32
H = 40
b = 0.3
0.45
0.6
0.75
0.9
0.45
0.6
0.75
0.9
1.2
0.45
0.6
0.75
0.9
1.2
0.6
0.75
0.9
1.2
1.5
3.0
2.4
1.9
1.6
1.5
1.3
2.4
2.0
1.8
1.6
1.4
2.8
2.4
2.1
1.9
1.6
2.7
2.4
2.2
1.8
1.6
4.5
2.8
2.2
1.9
1.7
1.6
2.8
2.4
2.1
1.9
1.6
3.2
2.8
2.4
2.2
1.9
3.1
2.8
2.5
2.1
1.9
6.0
3.1
2.5
2.1
1.9
1.7
3.1
2.6
2.3
2.1
1.8
3.6
3.1
2.7
2.5
2.1
3.5
3.1
2.8
2.4
2.1
7.5
3.3
2.7
2.3
2.1
1.9
3.3
2.9
2.6
2.3
2.0
3.9
3.3
3.0
2.7
2.3
3.8
3.3
3.0
2.6
2.3
9.0
3.6
2.9
2.5
2.2
2.1
3.6
3.1
2.8
2.5
2.2
4.2
3.6
3.2
2.9
2.5
4.1
3.6
3.3
2.8
2.5
10.5
3.8
3.1
2.7
2.4
2.2
3.8
3.3
2.9
2.7
2.3
4.5
3.8
3.4
3.1
2.7
4.3
3.8
3.5
3.0
2.7
12.0
4.1
3.3
2.8
2.5
2.3
4.1
3.5
3.1
2.8
2.4
4.7
4.1
3.6
3.3
2.8
4.6
4.1
3.7
3.2
2.8
13.5
4.3
3.4
3.0
2.7
2.4
4.3
3.7
3.3
3.0
2.6
5.0
4.3
3.8
3.4
3.0
4.8
4.3
3.9
3.3
3.0
15.0
4.5
3.6
3.1
2.8
2.5
4.5
3.8
3.4
3.1
2.7
5.2
4.5
4.0
3.6
3.1
5.0
4.5
4.0
3.5
3.1
16.5
4.6
3.8
3.2
2.9
2.6
4.6
4.0
3.6
3.2
2.8
5.4
4.6
4.1
3.8
3.2
5.2
4.6
4.2
3.6
3.2
18.0
4.8
3.9
3.4
3.0
2.8
4.8
4.1
3.7
3.4
2.9
5.6
4.8
4.3
3.9
3.4
5.4
4.8
4.4
3.8
3.4
19.5
5.0
4.0
3.5
3.1
2.8
5.0
4.3
3.8
3.5
3.0
5.8
5.0
4.4
4.0
3.5
5.6
5.0
4.5
3.9
3.5
22.0
5.2
4.3
3.7
3.3
3.0
5.2
4.5
4.0
3.7
3.2
6.1
5.2
4.7
4.3
3.7
5.9
5.2
4.8
4.1
3.7
NOTES:
1
Tabulated depths include the 0.2 m additional depth required by Clause 6.4
The embedment depth should be not less than 0.5 m in any soil.
There are close similarities between Method 1 and 3 and later was adopted as a more practical
solution in AS/NZS 4676. Method 2 is completely arbitrary and while resulting in solutions
that have been seemingly conservative. The reality is that in the past the majority of poles have
been for lightly loaded and concurrent with some conservative planting depths for the design
load applied ,that the lines have performed well as you would expect.
Method 3 is the most appropriate practical and recommended method. It also provides a method
where soft soil conditions require the installation of bearing logs/ blocks to develop strength.
23
1.2 general
LVABC may be used as
(a)
(b)
The first element to fail should be the suspension support by failure of the
suspension clamp or the pole hardware supporting the suspension clamp. The cable
should not be allowed to slip through the suspension clamp as this causes insulation
damage, especially if an insulation piercing connector is fitted near the support.
(ii)
The second element to fail should be mains and service tee connections to minimize
the number of live cables lying on the ground.
(iii) The third element to fail should be the pole hardware supporting the strain clamp.
(iv)
This should be followed by pole footing failure, cable failure and pole failure.
Under the short duration load of Clause 3.3.2.1, the tangential tension in the cable should
not exceed 28% CBL. This is based on a 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
compounds.
(b)
The highest horizontal tension used for the everyday load (Clause 3.3.2.3) should take
into account the working ratings of cable tensioning equipment such as lugalls,
comealongs, etc. Also for 3 or 4 core cables experience has shown that the cores are
difficult to separate to fit Insulation Piercing Connectors at cable tensions exceeding
4.5 kN.
1.3.3 Clearances
The clearance requirements of Sections 8, 9 and 10 for Insulated Conductor, U 1000 V apply
to LVABC.
1.4 Facade cable
The mounting of LVABC on the facades (frontages) of buildings was the original and still the
most common method of using LVABC in France. Its initial use was in narrow laneways and
streets where poles could not be used. Australias capital and provincial cities have many such
laneways and narrow streets.
Before LVABC is attached to the facade agreement on the following issues should be reached
with all the building owners:
(a)
Liability for all expenses resulting from the attachment of the cable to the facade.
(b)
Conditions relating to building owners painting the LVABC and any attachments to
further harmonize the cable with the facade.
(c)
Liabilities for damage to the cable system resulting from failure of the building or its
facade.
(d)
Liabilities for any damage done to the facade resulting from the attachment of the cable
system.
(e)
(f)
(b)
Non-tensioned construction is used in most installations and the cable is only tight
enough to remove any twists. The cable is lifted onto the wall brackets and has sufficient
tension so that there are no unsightly sags between supports.
(i)
Strain clamps are recommended for all runs but should be used to terminate cable
for all runs over 10 m. In-line strains are used so that no run between strain clamps
is more than 60 m.
(ii)
Tensioned construction is seldom used but is applicable where the facade cable crosses
over laneways or other discontinuities. An everyday tension of 1.4 kN is recommended
for 4 95 mm2. Tensions for other sizes should be chosen to give equivalent sag to this.
(i)
Strain clamps are used for all runs and in-line strains are used so that no run
between strain clamps is more than 60 m.
(ii)
1.4.2 Clearances
Where the cable is in excess of 300 mm from the facade of the building which supports it, the
requirements of Sections 8 and 9 apply.
The minimum clearance from any part of the facade of the building which supports it, to any
position the cable may assume due to the influence of load current and solar radiation, should be
as specified in Table 16.1. Mechanical barriers or enclosures may be used to reduce these
clearances.
TABLE 16.1
CLEARANCES FOR FACADE SYSTEMS
Clearance
Facade situation
Minimum
permissible
clearances
m
2.5
Comments
0.3
0.5
1.0
0.05
Whichever is wider
1.5 References
SEBIRE, J. and GEELAN, G. Mechanical Design and Co-ordinated Mechanical Failure of Low
Voltage ABC Lines. Distribution 2000, May 1991, Sydney Australia.
MORGAN, V.T. The Current Rating of Aerial Bundled Cables. Distribution 2000, May 1991,
Sydney Australia.
SEBIRE, J. The Facade Mounting of Low Voltage ABC. Distribution 2000, May 1991, Sydney
Australia.
MCLEOD, D., DEMKO, M. and GRIFFIN, M. Design of Low Voltage Networks Using LVABC.
Distribution 2000, May 1991, Sydney Australia.
MURRAY, T. and KREMER, H. Design Aspects of LVABC Lines in Severe Environments.
Distribution 2000, November 1993, Melbourne Australia.
24
1.6 General
HVABC is fully insulated for the service voltage. There are three types, as follows:
(a)
Metallic Screened High Voltage Aerial Bundled Cable (to AS/NZS 3599.1)MSHVABC
(b)
Non-metallic Screened High Voltage Aerial Bundled Cable (to AS/NZS 3599.2)
NMSHVABC
(c)
In Self-supporting High Voltage Aerial Bundled Cable the mechanical load has to be transferred
to the insulated conductors and is supported at intermediate structures on line insulators rated
for the nominal operating voltage. Cables at low tension are tensioned with clamps similar to
LVABC strain clamps but at higher tensions the bundle is opened out and bare conductor
terminations are fitted to the core conductors.
The rest of this Clause covers MSHVABC and NMSHVABC only, which use a support
conductor to carry the mechanical load.
1.7 Mechanical
MSHVABC and NMSHVABC consist of three cores wrapped around a support conductor. In
both types the support conductor mechanically supports the cable bundle and in NMSHVABC it
also provides electrical earthing.
The cable bundle is supported at intermediate supports on suspension clamps with the support
conductor firmly clamped and the cores clamped sufficiently to prevent the cores slipping
relative to the support conductor. Measures should be taken to maintain the insulation screens of
the three cores of NMSHVABC and the metallic screens of MSHVABC within the prospective
touch voltage limits in Section 11 by earthing at appropriate intervals.
On strain or tension structures the support conductor is separated from the bundle and
terminated using standard bare conductor fittings. In both cable types measures should be taken
to prevent the cores slipping relative to the support conductor and again measures should be
taken to maintain the insulation screens or metallic screens within appropriate potentials.
At intermediate supports consideration may also be given to using line fittings specifically
designed to cause the cable to separate from its support at a predetermined load, such as that
caused by a falling tree or limb.
1.8 Electrical
In MSHVABC the fault return path is provided by the metallic screens in each core, but
measures should be taken to ensure that the support conductor is not damaged by the passage of
fault current to the extent that it cannot support the cable for mechanical loading and ground
clearance considerations.
In NMSHVABC the support conductor should be effectively earthed to ensure that it
(a)
(b)
Also, measures should be taken to ensure that the support conductor is not damaged by the
passage of fault current to the extent that it cannot support the cable for mechanical loading and
ground clearance considerations.
1.9 Clearances
The clearance requirements of Sections 8, 9 and 10 for U 1000 V, Insulated with Earthed
Screen, apply to HVABC.
1.10 references
WILLIAMSON, C.E., CHEALES, J.A., and MCLEOD, D. Overview of Insulated HV Overhead
Systems and Applications. Distribution 2000, May 1991, Sydney Australia.
COULTER, R., SEBIRE, J. and MCLEOD, D. Some Design Aspects of High Voltage Nonmetallic Screened Aerial Bundled Cable Systems. Distribution 2000, May 1991, Sydney
Australia.
KENT, H., CLAY, J., RICHTER, K. and MCLEOD, D. Economic and Technical
Considerations of High Voltage Insulated Overhead Lines. Distribution 2000, November 1993,
Melbourne Australia.
SEBIRE, J., PIASENTIN, S. and SOUPROUNOVICH, K. The Development, Introduction and
Experience with HVABC in the State Electricity Commission of Victoria. Distribution 2000,
November 1993, Melbourne Australia.
25
1.11 general
Covered conductor manufactured to AS/NZS 3675 may be used in a similar manner to an open
wire 11 to 33 kV bare overhead system, except that the following should apply:
(a)
The system should include adequate protection to prevent burndown at support points.
Such matters as lightning surge protection, fault clearing times and the need for fault
current limitation should be considered.
(b)
(c)
Clearance between phases may be reduced (See Clause 10.3 Note 3).
(d)
(e)
Consideration may be given to reducing the permissible limits of approach for safe
working conditions.
Covered conductor to AS/NZS 3675 contains a water blocking compound to prevent the
migration of water under the covering and between the wires. Covered conductors have
previously been used in Australia without water blocking. These conductors suffered corrosion
of the conductor under the covering and eventual failure. The corrosion also contributed to
conductor burndown.
1.12 CC
CC can withstand intermittent contact with conductive material between phases or to ground,
e.g. trees and branches, but should not remain in permanent contact.
1.13 CCt
CCT has the following additional features:
(a)
Clearance between phases and to trees may be further reduced compared with CC
(b)
CCT has electrical and mechanical characteristics which permit it to remain in contact
with tree limbs for an extended period of time. In determining the period, account should
be taken of
(i)
(ii)
(d)
(e)
Suitable for use in spacer cable systems, however, consideration should be given to
using CCT which has an outer layer of tracking resistance material, especially at nominal
voltages of 22 kV and above.
1.14 Clearances
The clearance requirements of Sections 8, 9 and 10 for U 1000 V, Bare or Covered, apply to
CC.
The clearance requirements of Sections 8, 9 and 10 for U 1000 V, Insulated without earthed
screen, apply to CCT, providing that the covering thickness is appropriate to the operating
voltage.
1.15 references
WILLIAMSON, C.E., CHEALES, J.A., and MCLEOD, D. Overview of Insulated HV Overhead
Systems and Applications. Distribution 2000, May 1991, Sydney Australia.
ELFORD, R.F., KATO, K., NAGASAKA, H., and MATSUMOTO, J. Development and
Introduction of Aerial Insulated Unscreened Conductor (IUC) in South Australia. Distribution
2000, May 1991, Sydney Australia.
KENT, H., CLAY, J., RICHTER, K. and MCLEOD, D. Economic and Technical
Considerations of High Voltage Insulated Overhead Lines. Distribution 2000, November 1993,
Melbourne Australia.
HINKKURI, A., LEHTINEN, I. AND NOPONEN, K. ON THE DESIGN AND
EXPERIENCE WITH HIGH VOLTAGE COVERED CONDUCTOR SYSTEMS. Distribution
2000, November 1993, Melbourne Australia.
MCLEOD, D., KATO, K. and MCPHEE, A. Development of 22 kV Covered Conductor for
SECV. Distribution 2000, November 1993, Melbourne Australia.
ELFORD, R. Design Considerations for Covered Conductor (CC) Distribution. Distribution
2000, November 1993, Melbourne Australia.
RICHTER, K. An Overview on Overhead Insulated Systems in South Australia. Distribution
2000, November 1993, Melbourne Australia.
26 SELECTION OF CONDUCTORS
SELECTION OF CONDUCTORS FOR HOSTILE ENVIRONMENTS
This Appendix provides an indication of the relative corrosion performance of various
conductor types. The recommendations should be modified by local experience, for example,
for salt spray pollution the relative distances from the source depend upon the prevailing winds
and the terrain. Special circumstances such as crop dusting, which has been known to produce
severe effects, should also be taken into account.
TABLE D1
SELECTION OF CONDUCTORS FOR HOSTILE ENVIRONMENTS
Conductor
type
Industrial pollution
Open ocean
Acidic
Alkaline
AAC
AAAC/6201
AAAC/1120
ACSR/GZ
ACSR/AZ
ACSR/AC
SC/GZ
SC/AC
OPGW
HDCu
NOTES:
1.
= good performance
2.
= average performance
3.
= poor performance
When selecting a conductor for a hostile environment the following factors should be
considered:
(a)
(b)
Ensure that all fittings are compatible so that electrolytic corrosion does not occur.
(c)
(d)
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.
THERMAL LIMITS
General
Knowledge of the behaviour of conductors when subjected to various heating conditions is
essential when designing and operating overhead lines.
For distribution lines where a lower standard of load control and monitoring usually applies it is
recommended that an additional margin be applied. Maximum Design Temperatures of 50C to
65C are commonly used.
kt c1c2ec3(20)
In most cases the conductor exposure period at elevated temperatures is very small relative to an
everyday exposure temperature assessed to be 20C hence the above equation may be reduced
to:
t
kt c1c2
time in years
where
t eq ( i )
( i 1)
=
teq(i)
the equivalent time in years for unit strain at stress level (i)
(i-1)
(i)
the stress level in MPa associated with time interval teq (i)
t(i-1)
interval
c 2t( i 1 )
where
Fault ratings
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; and
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.
Annealing
It is assumed that the electrical protection for the line will operate and that the duration of the
fault will be short, in the order of a few cycles to a number of seconds for distribution feeder
protection comprising initial clearance plus reclose clearance times. For such periods it may be
assumed that no heat will be dissipated from the conductor. A reasonable approximation of the
final temperature of the conductor is given by:
T2
Ar RJ 2 r
DC
1
1
= 20
+ T1 20 + e
Ar
Ar
where
T2
final temperature in C
T1
initial temperature in C
. . .D1
Ar
density in g/mm3
specific heat =
C20
Ac
T + T2
C 20 1 + Ac 1
20
2
J t
T + T2
20
DC 20 1 + Ac 1
T2 20 +
2
ln
Ar R
T 20 +
1
1
Ar
1
Ar
. . . D2
TABLE D2
CONDUCTOR CONSTANTS
Constants
Units
AAAC/
1120
AAC
AAAC/
6201A
HD
copper
SC/GZ
SC/AC
Ar
(at 20C) *
C1
0.00403
0.00390
0.00360
0.00381
0.00440
0.00360
R
(at 20C) *
mm
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
C20 **
Jg 1C 1
0.9
0.9
0.9
0.4
0.5
0.5
A c**
C1
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:
V T Morgan, Rating of Bare Overhead Conductors for Intermittent and Cyclic Currents, Proc
IEE, 1361-1376, 116(8), 1969.
V T Morgan, Rating of Conductors for Short-Duration Currents, Proc IEE, 555-570, 118(3/4),
1971.
From equation D2 the fault rating can be determined once an allowable final temperature has
been determined. Constants for specific conductor types are contained in the relevant Australian
Standards.
Aluminium loses approximately 10% of its tensile strength at a temperature of 210C 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 340C and commences melting at approximately 645C. The mechanical properties
of the steel core of ACSR are affected very little at these temperatures. Zinc melts at
approximately 420C. Copper loses 10% of its tensile strength at a temperature of 220C.
To provide for a loss of conductor tensile strength of less than 5% due to fault conditions over
its life, the following temperatures should not be exceeded. The rate of cooling is dependent on
the thermal mass of the conductor, therefore lower maximum temperatures are applicable to
conductors of large cross-section.
TABLE D3
GUIDELINES FOR 5% LOSS OF TENSILE STRENGTH
FOR TOTAL FAULT CLEARING TIME (INCLUDING RECLOSES)
Approximate size
(mm)
Maximum
temperature
HDCu
60
200C
AAC, AAAC/1120,
ACSR/GZ,
100
160C
300 to 500
150C
100
220C
Conductor type
ACSR/AZ,
ACSR/AC
AAAC/6201A
SC/GZ, SC/AC
OPGW
400C
***
***Dependent on construction.
Reference: Roehmann, LF and Hazan, E Short time annealing characteristics of
electrical conductors, AIEE Trans 82/3 p1061, Dec 1963.
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