OVERHEAD LINE DESIGN HANDBOOK
Version 7.0 Date August 2009
Table of Contents
1
INTRODUCTION
7
2
DESIGN PHILOSOPHIES
9
2.1 3
Basic Methodology ELECTRICAL REQUIREMENTS
9 11
3.1
Clearance and Spacing for Overhead Lines
11
3.2
Tower top geometry
13
3.3
Transpositions
15
4
SELECTION OF CONDUCTOR Steady state thermal current rating Short-circuit thermal current rating
15 15 15
Conductor long term electrical performance Conductor Limit states
16 16
4.1
17
Sag-tension calculation
5
INSULATOR DESIGN Design for pollution
17 18
6
BASIS OF STRUCTURAL DESIGN 6.1.1 Determination of height 6.1.2 Loading on Structures 6.1.3 Limit State Design
22 22 22 23
7
ACTION ON LINES
24
8
SUPPORTS
26
9
FOUNDATION DESIGN
27
10
EARTHING
30
Earthing and Insulation of Stay Wires
33
Conductor Failure Protection
33
Broken Stay Wire Protection
33
11
WORKED EXAMPLES
36
11.1
Electrical Clearances between conductors
36
11.2
Determination of conductor rating
37
References
38
11.3
38
Design for lightning performance
11.4 Electrical and Mechanical Design for Insulators 11.4.1 Design for pollution 11.4.2 Design for power frequency voltages (Wet withstand requirement) 11.4.3 Design for switching surge voltages 11.4.4 Selection of Insulator to meet Electrical Performance 11.4.5 Insulator mechanical design
40 40 41 41 41 43
References
43
11.5 Limit State Design Worked Examples 11.5.1 Pole Tip Load Calculation CALCULATIONS Distibution Worked Example 3
44 45 52 54
SWING ANGLE CALCULATIONS
56
APPENDICES
57
APPENDICES
57
11.6
Conductor Clashing
57
12
ROUTE SELECTION PROCESS
59
12.1
Risk Management Principle
59
12.2
Prudent Avoidance Principle
59
12.3
Aesthetic Considerations
59
12.4
Electric and Magnetic Fields
60
13
LAYOUT DESIGN PROCESS
60
Terrain
61
Terrain Model
61
Alignment
62
13.1
Pole Locations in Traffic Corridors
72
13.2
Railway and Tramway Crossings
73
13.3
Waterway Crossings
73
13.4
Co-ordination with other Services
73
13.5
Aerial Lines in the Vicinity of Aircraft
74
13.6
Rural Activities in Proximity to Line
74
13.7
Ruling Span
75
14
COST OF OVERHEAD LINE (BY COMPONENTS)
75
15
GUIDELINES FOR POLE LOCATION
77
15.1
Acceptable Location of Poles in Road Corridors
77
15.2
Special Considerations for Slip based poles
77
15.3
Aerial Lines in the Vicinity of Aircraft
78
15.4
Country Line Road Crossings
79
15.5 Markers Permanent Markers Temporary Markers Over Crossing Markers
79 79 80 80
16
VEGETATION CLEARANCES
80
17
LIST OF AVAILABLE LINE DESIGN PROGRAMS
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
COMMENTARY ON APPENDIX F - TIMBER POLES
Clause F1
General
90
Clause F1.2 Characteristic strengths and elastic moduli 21
COMMENTARY ON APPENDIX I - CONCRETE POLES
22
APPENDIX L - STRUCTURE FOOTING DESIGN
L1
GENERAL PRINCIPLES
L2 GEOTECHNICAL PARAMETERS OF SOILS AND ROCKS
90 97 100 100 100
L3 FOOTING DESIGN OF DIRECTLY EMBEDDED OVERHEAD LINE POLES FOR LATERAL LOADS AND MOMENTS 101 3.1.1 Bearing strength 104 3.2 Shear strength 105 3.3 FOOTINGS AND EMBEDMENT DEPTH IN SOILS 23
LOW VOLTAGE AERIAL BUNDLED CABLE
105 82
1.2 general
82
1.3 Aerial cable 1.3.1 Supports 1.3.2 Cable tension 1.3.3 Clearances
82 82 82 82
1.4 Facade cable 1.4.1 Mechanical design 1.4.2 Clearances
82 83 83
1.5 References
84
24
85
HIGH VOLTAGE AERIAL BUNDLED CABLE
1.6 General
85
1.7 Mechanical
85
1.8 Electrical
85
1.9 Clearances
86
1.10 references
86
25
86
COVERED CONDUCTOR SYSTEMS
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
SELECTION OF CONDUCTORS FOR HOSTILE ENVIRONMENTS
88
THERMAL LIMITS General Maximum design operating temperatures Conductor permanent elongation Fault ratings
88 88 89 91 92
Handbook for the Overhead Line Design Standard 1
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.
Determine Design Inputs / Parameters Select Route Select Conductor Type Select Structure Suite Conduct Route Survey and Draw Ground Line Profile Nominate Structure Type/Strength, Height and Position Produce Layout Design Establish Final Electrical Parameters Obtain Relevant Approvals Produce Detailed Drawings and Specification Conduct Design Review and Verification Provide Design Support for Construction Conduct Audit and Relevant Tests Document As-Constructed Records Monitor Performance of Overhead Line
2
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 it’s 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
Applicable to overhead lines where collapse of the line may be tolerable with respect to social and economic consequences. (Normal distribution lines)
Level II
Applicable to overhead lines where collapse of the line would cause negligible danger to life and property and alternative arrangements can be provided if loss of support services occurs. (Higher security distribution lines and normal transmission lines)
Level III
Applicable to overhead lines where collapse of the line would cause unacceptable danger to life or significant economic loss to the community and sever vital post disaster services. (Higher security transmission lines)
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
Temporary construction and construction equipment, e.g. hurdles, scaffolding and temporary line diversions with design life of less than 6 months
0.67
0.67
0.77
< 5 years
0.77
0.9
1.0
25 years
0.9
1.0
1.2
50 years
1.0
1.2
1.4
100 years
1.2
1.4
1.4
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. .
Clause 6.2.4 of the standard sets out additional security requirements. It requires that security requirements shall be provided in all designs to prevent or limit progressive or cascading structure failures in the event of collapse or failure of a support structure resulting from any external cause. In general, on major transmission lines longitudinal design loads relevant to residual loads for broken or terminated and aerial phase conductor are provided to meet this requirement. This is an important consideration as restoration costs and disruption to supply in the event of structure failure can be considerable. On distribution overhead pole lines, pole deflection (usually rotational and lateral or longitudinal ) combined with partial foundation deformation, will occur when abnormal longitudinal loads are applied. When a single pole structure fails and conductors are broken (due to say vehicle impact or storm debris overload) the adjacent pole structures deflect such that they may provide sufficient release of load in the conductors to limit the extent of damage, particularly when there is localized failure of the overhead line. It is most probable when a single pole fails due to ground line failure the conductor system will most probably restrain the pole from falling to the ground. However the conductor tensions in the adjacent spans will increase dramatically and pose a maintenance work safety issue. Where more extensive overload occurs due to major wind storm with extensive wind blown debris, or major flooding occurs the containment potential provides some benefit in conserving major structure elements, whereas the aerial conductors most probably will be brought down.
3
ELECTRICAL REQUIREMENTS 3.1
Clearance and Spacing for Overhead Lines
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
U
Over land other than the carriageway of roads
Over land which due to its steepness or swampiness is not traversable by vehicles more than 3 m in height
Bare or insulated conductor or any other cable U ≤ 1000 V OR
5.5
5.5
4.5
6.0
5.5
4.5
Insulated conductor with earthed screen U > 1000 V Insulated conductor without earthed screen U > 1000 V Bare or covered conductor 1000 V
6.7
5.5
4.5
33 V
6.7
6.7
5.5
132 kV
7.5
7.5
6.0
Other clearances given in the Overhead Line Design Standard are: • • •
Clearances to Earthed Structures – Table 3.5 HV AC Live Line Approach Distances – Table 3.6 Clearances from Structures – Table 3.8
A coverage of vegetation clearances are given in Appendix …. The spacing of conductors is determined by considerations, which are partly electrical and partly mechanical. Usually conductors will swing synchronously (in phase) with the wind, but with long spans and small size of conductors, there is always possibility of the conductors swinging nonsynchronously, and the size of the conductor and the maximum sag at the centre of the span are factors, which should be taken into account in determining the phase distance apart at which they should strung. As a rule of thumb, minimum horizontal spacing between conductors should not be less than 1% of the span length in order to minimize the risk of phases coming into contact with each other during swing. The conductor separation in the Overhead Line Design Standard is as follows.
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
Y
is the projected vertical distance in metres between the conductors at mid span;
U
is the r.m.s. vector difference in potential (kV) between the two conductors when each is operating at its nominal voltage.
k
is a constant, normally equal to 0.4. Where experience has shown that other values are appropriate, these may be applied.
D
is the greater of the two conductor sags in metres at the centre of an equivalent level span and at a conductor operating temperature of 50°C in still air
Ii
is the length in metres of any free swing suspension insulator associated with either conductor.
Tower top geometry
There are a number of electrical clearance which determine the tower top geometry. These clearances are: (A)
Maintenance approach and live line working under 100 Pa wind
(B)
Switching and lightning impulse flashover under 300 Pa wind
(C)
Power frequency flashover under 500 Pa wind
(D)
Hand reach under 100 Pa wind
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)
The minimum recommended weight to wind span ratio is 0.7
(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.
FIGURE 2 STRUCTURE GEOMETRY FOR 132 KV LINE SHOWING ELECTRICAL CLEARANCES
• Insulator Swing Angles – T Gillespie • Produce worked example for insulator swing angle and blowout • Provide another drawing showing a line post insulator
Blowout clearance calculations are useful to determine clearances along the span to structures along the route. The recommended conditions for calculating blowout are: (1)
500 Pa wind on conductor
(2)
15 deg C or ambient temperature applicable to the location of line
(3)
3.3
Include the horizontal displacement of a swinging insulator
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.
4
SELECTION OF CONDUCTOR
The selection of conductor size is primarily governed by two factors: 1. Electrical requirement 2. Mechanical strength Electrical requirements Steady state thermal current rating The steady state thermal current rating of a conductor is the maximum current inducing the maximum steady state temperature for a given ambient condition and is based on conductor heat gain equals conductor heat loss that is— Pj + P s = P r + P c
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.
Conductor long term electrical performance The long term performance of a conductor is dependent on the degree of electrical and mechanical overload and the weathering effects. Conductors will suffer some degree of annealing (loss of mechanical strength) and this is dependent on the operating and overload temperature on the conductor.
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]
FIGURE 1 LIMIT STATES OF CONDUCTOR DESIGN
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
– vibration limit (see Note 1); or – 0.5 conductor CBL (see Note 2)
0.7 conductor CBL (see Note 3)
Selection of Conductors – G Brennan and G Bruce
Selection of Conductor Tensions Topics to cover: • Fatigue endurance limit • Lower tensions based on service experience • Lower tensions for short spans • Adjacent span effects 4.1
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 =
L ⎛ c ⎜ cosh 2c ⎝
⎞ − 1⎟ ⎠
C = Horizontal Tension / Weight Where: L = horizontal length (m) c = catenary constant (m) T = horizontal tension (N) w = weight of conductor (N/m) 5
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)
Creepage (or leakage) distance.
(b)
The ability of the material to endure the electrical activity without being degraded.
(c)
The shape of the insulator to assist in reducing the likelihood of contamination collection and facilitate washing.
AS 4436 provides guidance on the selection of insulators for polluted conditions. The basic concept is to increase the surface creepage distance so that it is long enough to prevent a pollution flashover across the surface.
Mechanical Design of Insulators Explanation of limit states – T Gillespie There are three states for the mechanical design of insulators identified in the Detailed Procedure, these being the— (a) everyday load; (b) serviceable wind load; and (c) failure containment load.
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)
failure containment load at 1300 Pa
Conductor tension at 1300 Pa = 39162 N Component strength factor for ceramic insulator = 0.8 (Table 6.5) Minimum insulator ultimate strength = 39162 / 0.8 = 48952 N Calculate the strength of a composite line post insulator used to support oxygen conductor in a clamp top with a weight of 0.925 kg/metre, weight span of 200 metres, and strung to everyday tension of 20% CBL. (b)
everyday load
Conductor weight = 0.925 * 9.806* 200 N = 1814 N Longitudinal load for 3:1 adjacent span ratio, and max operating temperature of 75 deg C = 5000 N
Resultant bending moment load = SQRT (1814^2 * 5000^2) = 5318 N Component strength factor for composite post insulator = 0.9 (Table 6.5) Insulator maximum design cantilever load = 5318 / 0.9 = 5909 N Note: The maximum design cantilever load of a post insulator is typically 40 to 50% of the ultimate strength. (c)
serviceable wind load at 500 Pa
Conductor weight = 0.925 * 9.806* 200 N = 1814 N Longitudinal load for 3:1 adjacent span ratio, and max operating temperature of 75 deg C = 5000 N Resultant bending moment load = SQRT (1814^2 + 5000^2) = 5318 N Insulator ultimate cantilever strength without transverse load = 5318 / 0.9 = 5909 N Transverse compressive load = 0.0238*500*200 = 2380 N Simplified method: Compressive strength of 2.5 inch line post = 50 kN Derating factor = 1-2380 / 50000 = 0.94 Insulator maximum design cantilever load with transverse load = 5909 / 0.94 = 6200 N (d)
failure containment load at 1300 Pa
Conductor weight = 0.925 * 9.806* 200 N = 1814 N Longitudinal load for 3:1 adjacent span ratio, and max operating temperature of 75 deg C = 5000 N Resultant bending moment load = SQRT (1814^2 * 5000^2) = 5318 N Insulator ultimate cantilever strength without transverse load = 5318 / 0.9 = 5909 N Transverse compressive load = 0.0238*1300*200 = 6188 N Simplified method: Compressive strength of 2.5 inch line post = 50 kN Derating factor = 1- 6188 / 50000 = 0.87 Insulator maximum design cantilever strength with transverse load = 5909 / 0.87 = 6800 N Comments: (1)
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)
The design options to support the failure containment load are:
•
Brace 2.5 inch post with a long rod insulator
•
Limit the line layout to an adjacent span ratio of 2 or less
•
Use a 3 inch post which has a MDCL of around 9 kN
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
Conductor weight = 0.925 * 9.806* 400 N = 3628 N Assume no longitudinal load due to free swinging insulator Component strength factor for long rod insulator = 0.5 (Table 6.5) Insulator specified mechanical load = 3628 / 0.5 = 7256 N (b)
ultimate strength state under 1300 Pa wind
Conductor weight = 0.925 * 9.806* 400 N = 3628 N Assume no longitudinal load due to free swinging insulator Transverse load = 0.0238 * 1300 * 400 N = 12376 Resultant load = SQRT (3628^2 + 12376^2) = 12896 N Component strength factor for long rod insulator = 0.5 (Table 6.5) Insulator specified mechanical load = 12896 / 0.5 = 25793 N (c)
failing containment load under broken conductor
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)
The minimum recommended strengths are based on the requirement to achieve a design life comparable to other line components
Distribution Line Insulator Examples Calculate the strength of a tension ceramic disc insulator used for moon conductor strung to everyday tension of 20% CBL. (e)
failure containment load at 900 Pa
Conductor tension at 900 Pa = 8617 N Component strength factor for ceramic insulator = 0.8 (Table 6.5) Minimum insulator ultimate strength = 8617 / 0.8 = 10771 N Refer to Note 1 in Appendix CC which states insulator strength to be greater than conductor CBL or coordination of strength between conductor, insulator, fittings, crossarm and structure. To achieve a long life for the ceramic disc insulator, the minimum standard of 70 kN is recommended.
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
Conductor weight = 0.34 * 9.806* 100 N = 333 N Longitudinal load for 2:1 adjacent span ratio (75 and 150 m spans), and max operating temperature of 75 deg C = 3300 N Resultant bending moment load = SQRT (333^2 * 3300^2) = 3316 N Component strength factor for ceramic post insulator = 0.8 (Table 6.5) Insulator minimum failing load = 3316 / 0.8 = 4145 N (g)
serviceable wind load at 500 Pa
Conductor weight = 0.34 * 9.806* 100 N = 333 N Longitudinal load for 2:1 adjacent span ratio, and max operating temperature of 75 deg C = 3300 N Resultant bending moment load = SQRT (333^2 * 3300^2) = 3316 N Insulator minimum failing load without transverse load = 3316 / 0.8 = 4145 N Transverse compressive load = 0.0143*500*100 = 715 N Simplified method: Compressive strength of ceramic post = 100 kN Since the transverse compressive load is insignificant compared to the compressive strength of the ceramic post, this can be ignored. (h)
failure containment load at 900 Pa
Conductor weight = 0.34 * 9.806* 100 N = 333 N Longitudinal load for 2:1 adjacent span ratio, and max operating temperature of 75 deg C = 3300 N Resultant bending moment load = SQRT (333^2 * 3300^2) = 3316 N Insulator minimum failing load without transverse load = 3316 / 0.8 = 4145 N Transverse compressive load = 0.0143*900*100 = 1287 N Simplified method: Compressive strength of ceramic post = 100 kN Since the transverse compressive load is insignificant compared to the compressive strength of the ceramic post, this can be ignored.
Produce worked examples for the following insulators: - T Gillespie • • • •
Tension string Suspension or I string Line post Pin (G Bailey to provide)
6
BASIS OF STRUCTURAL DESIGN
6.1.1 Determination of height The factors governing the height of structure are: • • • •
Minimum permissible ground clearance, h1 Maximum sag, h2 Vertical spacing between conductors, h3 Vertical clearance between earthwire and top conductor, h4
The total height of structure will be determined by: H T = h1 + h2 + h3 + h4
6.1.2 Loading on Structures The loads on a structure consist of three mutually perpendicular systems of load acting vertical, normal to the direction of line, and parallel to the direction of the line. These loads can be described as: • • •
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
=
V50 Md Mz,cat MsMt
Mz,cat =
gust winds speed multiplier for terrain category at height z. Refer AS/NZS 1170.2 for all regions use Table 4.1(A).
Md
=
wind direction multiplier.
Ms
=
shielding multiplier.
Mt
=
topographic multiplier for gust wind speed.
V50
=
basic regional wind velocity for the region corresponding to the 50 year return period.
The design pressure qz shall be calculated as follows:
qz
Mrel x 0.6Vz2 × 10−3 kPa
=
6.1.3 Limit State Design Current practice in Australia for the design of Overhead Line Structural Components is to use a Limit State design approach as set out in ENA C(b)1 Guidelines for Design and Maintenance of Overhead Distribution and Transmission Lines. The Limit State design approach uses a reliability based (risk of failure) approach to match component strengths (modified by a factor to reflect strength variability) to the effect of loads calculated on the basis of an acceptably low probability of occurrence. φRn > effect of loads ( MRel Wn + ΣγxX) where X
=
the applied loads pertinent to each loading condition Reliability multiplier – given in Table 3
MRel = γx
=
are load factors which take into account variability of loads, importance of structure, stringing, maintenance and safety considerations etc.
Wn
=
wind load based on a 50 year return period scaled by the appropriate reliability load factor or specified design wind pressure
φ
=
the strength factor which takes into account variability of material, workmanship etc.
Rn
=
the nominal strength of the component
Some of the Limit State load cases given in the Overhead Line Design Standard are as follows: The Ultimate Strength Limit State Condition
φ Rn > Wn+1.25Gc +1.1Gs + 1.25 Ft Where: Wn = Effect of transverse wind loads Gc = Vertical dead loads resulting from conductors under limit state wind conditions
Gs = Vertical dead loads resulting from non conductor loads Ft = Intact conductor tension loads under limit state wind conditions φ R = Component design stress for limit state condition The Maintenance Load Condition
φ R > 1.1Gs +1.5 Gc +2.0Q + 1.25 Ft Where: Gc = Vertical dead loads resulting from conductors under everyday condition Gs = Vertical dead loads resulting from non conductor loads Q = Maintenance loads Ft = Intact conductor tension loads under maintenance wind Component Strength Factors Wood Poles – Preserved The relevant component strength factor for a preserved wood poles is dependent on the following characteristics and usage of the pole • Durability class • Strength class • Security class • Design life
7
ACTION ON LINES
Conductor Everyday Load Horizontal Tension The recommended weather cases used in design of overhead line conductor tensions are given in Table … Condition
Temp
Wind
Maximum Tension Refer Table Z1
Fatigue Endurance Conditions Design Everyday Condition Ultimate wind
Avg temp for coldest month
Design at 0.5 to 7 m/sec
Avg ambient temp for year
0 Pa
Refer Table Z1
Avg ambient temp for year
Regional design value
.5 CBL for linear .7 CBL for nonlinear
Initial / Final Final
Servicability wind – electrical Cold Condition
Avg ambient temp for year Coldest day of year based on design life
Ice Loading – 10 Coldest day of year mm thickness based on design life Snow loading – up to 100 mm thickness Conductor runout Conductor pretension Sagging Maintenance Failure Containment
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 • •
900 Pa for conductors 1300 Pa for round surfaces such as poles
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
Applicable Wind Loads Servicability
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
Pole Strength and Deflection Design The recommended limit state wind pressures for distribution designs for a typical life of 50 years in Regions A and B are: Ultimate Loads (WN) • •
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 ??.
φ Rn > Wn+1.25Gc +1.1Gs + 1.25 Ft For stayed poles with long length and small diameter, the buckling failure mode of the pole should be considered. Consideration should also be given to the P delta effects should they occur. The Euler buckling failure equations can be found in the relevant codes (eg AS1720). Servicability Limits Sustained Everyday tension loads on angle and termination poles • •
0 Pa for conductors 0 Pa for round surfaces such as poles
Deflection limits for maintenance and clearances • •
100 Pa for conductors 300 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.
9
FOUNDATION DESIGN
The foundation is called upon to resist the following types of forces: • • • •
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.
Foundation for poles (distribution lines) – L Elder •
Use simple formula
Distribution pole foundation design There are various methods used for pole foundation design and these are covered in Table … The Brinch Hanson method is regarded as the superior method for pole structures, however more simple techniques, such as that outlines in AS4676 have been found to be suitable for intermediate poles in firm soil and with small conductors. Table … Foundation Design Brinch Hanson
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
Applies to firm soil and small conductors assoc with intermediate poles Applies to firm soil and small conductors assoc with intermediate poles
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)
Ensure protective equipment will operate in faulted situations.
(e)
Provide acceptable reliability (lightning performance) on the line.
(f)
Control touch and step potentials around the base of the structure.
(g)
Provide a conductive path for fault current.
(h)
Avoid damage to properties and equipment.
The dimensioning of earthing systems considers the following requirements: (i)
To ensure mechanical strength and corrosion resistance.
(ii)
To withstand, from a thermal point of view, the highest fault current as determined by calculation
(iii) Limit lightning induced voltages on earth down leads The transfer of potential by nearby metallic objects may occur due to fault currents flowing in the earth system.
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)
Risk Based Approach to Earthing The risk based approach is covered in the ENA EG-0 Power System Earthing Guide Part 1: Management Principles Risk Based Earthing Examples: 1
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)
Installation of NER or NEX to limit fault current to typically 1000 A
(3)
Installation of grading ring – this would lower prospective touch voltage
(4)
Reduce protection clearing times – at 0.5 seconds, the prospective touch limit is 4,000 volts
2
Conductive distribution pole in an 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 = 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)
Combination of (2) and (3) – still above limit
(6)
Combination of (2 and (4) – meets limit
(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.
Distribution Earthing Systems Multiple Earthed Neutral (MEN) In a low voltage MEN system of earthing the elements of an installation that require earthing are commonly connected to earth, and in addition are connected to the neutral conductor of the supply system. This results in a well distributed, low impedance earthing system with many connections to the general mass of the earth. A well connected MEN system has a resistance of less than 1 ohms. Common Multiple Earthed Neutral (CMEN) This is where the HV and LV earthing systems are commonly bonded together with the LV MEN customer installation. With this type of system special consideration should be given to protection against HV earth faults and EPR. Where CMEN systems are installed, an MEN value of <1ohm is desirable. Separate Earthed System A separated earthing system is implemented with a pole top transformer by providing high voltage (HV) and low voltage (LV) earths on opposite sides of the pole and installing a nonconductive covering for the earthing conductors within 2.4m of the ground. Again earth electrode separation should be kept to the length of the electrode or 4m at a minimum. Where a separate earthed system is installed, a resistance of 30 ohms or less is desirable. Earthing and Insulation of Stay Wires Stay wires on lines should have insulators installed to limit the chance of an energised stay wire coming into contact with the public or staff. There are two possible mechanisms that may energise a stay wire; a conductor falling and energising the stay wire and a broken stay wire coming in contact with live conductors. Mitigations methods for either scenario are given below: Conductor Failure Protection Stay wires within 2.4 metres of the ground should be earthed in accordance with Clause 11 unless they are insulated by means of an insulator placed in the stay wire. The stay wire insulator shall be placed so its lowest point is not less than 2.4 metres above the ground. The stay wire insulator must also be placed so it is lower than the lowest conductor, excluding any underslung earth wire. The wet flashover voltage of the insulator must be 50% greater than the highest conductor on the pole phase to earth voltage.
Broken Stay Wire Protection
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
U
=
33
k
=
0.4
D
=
6.07
li
=
0
X 2 + (1.2Y ) 2 ≥
U + k D + li 150
1.052 + (1.2Y ) 2 ≥
33 + 0.4 6.07 + 0 150
1.052 + (1.2Y ) 2 ≥ 0.22 + 0.985 1.052 + (1.2Y ) 2 ≥ 1.205 1.2 Y ≥ 1..2052 − 1.052 Y≥
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
=
Va2 + Vb2 − 2 Va Vb Cos φ from ‘U’ above
=
⎛ 33 ⎞ ⎛ 11 ⎞ 33 11 × Cos120° ⎜⎜ ⎟⎟ + ⎜⎜ ⎟⎟ − 2 × 3 3 ⎝ 3⎠ ⎝ 3⎠
2
2
=
22.9 kV
∴X
=
0
U
=
22.9 (the difference in the vector r.m.s. potential of the circuit voltages)
k
=
0.4 (Region A)
D
=
6.07 (greater of the two sags)
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
(1.2Y ) 2 ≥ 0.153 + 0.985 1.2Y ≥ 1.138 Y≥
1.138 1.2
Y ≥ 0.948
11.2 Determination of conductor rating Once a conductor and its maximum operating temperature have been chosen, the conductor rating can be calculated. The method is based on the heat balance equations where Heat In (Solar Radiation Current Heating) = Heat Out (Convection Cooling from Wind and Radiated Losses). A coverage of the method is given in Reference [1]. Should further detail be required refer to Reference [2]. TNSP have agreed on a common method for conducting conductor ratings [Ref 3]. Conductor ratings are usually calculated for a combination of ambient temperatures and wind speeds. Guidelines for the use of these parameters are given in Table 4.1.
TABLE 4.1 AMBIENT TEMPERATURES AND WIND SPEEDS FOR CONDUCTOR RATINGS Rating type
Ambient temperature (°C)
Wind speed (ms −1 )
Summer noon normal
Max summer temp at location
0.5 to 1.0
Summer noon emergency
Max summer temp at location
1.0 to 2.0
Winter evening normal
Mild winter evening temp at location
0.5 to 1.0
Winter evening emergency
Mild winter evening temp at location
1.0 to 2.0
References 1
Electricity Supply Association of Australia, D (b) 5—1998, Current Rating of Bare Overhead Line Conductors published by Standards Association of Australia.
2
MORGAN, V.T. Thermal Behaviour of Electrical Conductors, Steady, Dynamic and FaultCurrent Ratings. Published in Brisbane by John Wiley and Sons Inc, 1991.
3.
“Standard Line Ratings Methodology for Transmission Network Services Providers”.
4
IEEE 738 Thermal Rating of Conductors
5
IEC 60909 “Calculation of the short-circuit currents in three phase a.c. systems”
6
EN 60865-1 “Calculation of the effects of short-circuit current”
11.3
Design for lightning performance
Lightning induced outages are one of the major cause of outages on overhead lines in areas of moderate to high ceraunic activity. A moderate ceraunic level is between 30 and 50 thunderdays per year, and high level above 50 thunderdays per year. The acceptable outage rate due to lightning is therefore one of the most dominant design parameters for an overhead line. In a low to moderate ceraunic activity area, an acceptable outage rate from lightning for overhead lines with overhead earthwires is typically 2 to 5 outages per 100 km per year. Process for design – balance shielding failures vs backflashover performance – T Gillespie
Estimation of line outages due to lightning There are 3 types of outages caused by lightning; shielding failure / direct strike , backflashover and induced voltage. A shielding failure occurs when the overhead earthwire fails to intercept the lightning stroke and the voltage developed by the surge current (1/2 stroke current x surge impedance of conductor) exceeds the insulation strength of the insulation. The electrogeometric model developed by IEEE (and incorporated in lightning prediction programs, like Flash) can be used to determine the probability of a shielding flashover. Backflashovers are the predominant cause of lighting induced flashovers on overhead lines protected by an earth or shield wire. The mechanism of a backflashover is that the lightning current flowing in the overhead earthwire couples inductively and capacitively with the phase conductor
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)
having wood in the flashover circuit (crossarm or pole);
(k)
Critical Flashover voltage (CFO) of the insulators; and
(l)
pole footing resistance.
Overhead earthwires are used to shield the line from lightning strikes and are usually installed on high reliability lines operating at sub-transmission and transmission voltage levels. They are also installed on overhead distribution lines for short distances (typically 800 m) out of a substation to protect the substation equipment from damaging overvoltages. One earthwire is usually sufficient to cater for shielding flashovers on structures below 20 m, but higher structures will need two earthwires to achieve effective shielding. With a single earthwire, the shielding angle is usually in the range of 30 to 40 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 =
[Iwood 2 + Iinsulator 2 ]1/2
...1
where Iwood
=
Iinsulator =
Impulse strength of wood Impulse strength of insulator
When an overhead earthwire is installed on powerlines, generally a down lead is run to earth to provide a low resistance path to ground. A low pole footing resistance not only reduces the probability of lightning induced backflashovers but also offers the following advantages: (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
Application of Surge Arresters
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)
Protection of pole mounted plant
(2)
Protection of underground terminations
(3)
Protect covered conductor from failure
(4)
To improve lightning outage rate
(5)
Where it is difficult or costly to install an overhead earthwire (eg retrofitting an existing line)
Electrical and Mechanical Design for Insulators
Design for pollution
When determining the insulation requirements for an overhead power line or an outdoor substation in a contaminated environment, the following criteria need to be considered: 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)
Minimum nominal specific creepage distance (2)
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)
ESDD is the equivalent salt deposit density.
(2)
Ratio of leakage distance measured between phase and earth over the r.m.s phase to phase voltage of the highest voltage of the equipment.
(3) Consideration should be given to increasing the creepage distances is areas where there are long periods without rainfall or very close to the marine coast
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
Design for switching surge voltages
Switching surge overvoltages up to 3 per unit peak voltage can arise when overhead lines are switched. The extent of this overvoltage is dependent on (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
Selection of Insulator to meet Electrical Performance
String Insulator Units:
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)
Pin - Two part Standoff Line Post with Tie Top Standoff Line Post with Clamp Top Station Post
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
Clevis Tongue - Normal Clevis Tongue - Fog Ball Socket - Normal Ball Socket - Fog 11 kV Insulators: Pin - Normal Pin - Fog Shackle Type SH.11 Line Post Tie Top Line Post Clamp Top Standoff Line Post with Trunnion Clamp Station Post Composite Long Rod
Composite Long Rod
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
Minimum nominal specific creepage distance
=
31 mm/kV for extreme contamination
Required creepage distance for 36 kV
=
1116 mm
Number of normal discs = 1116/300
=
3.72 → 4 discs
Number of fog discs = 1116/400
=
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
Minimum nominal specific creepage distance
=
25 mm/kV for heavy contamination
Required creepage distance for 300 kV
=
7500 mm
Number of normal discs = 7500/300
=
25 discs
Number of fog discs = 7500/400
=
18.75 → 19 discs
11.4.5
Insulator mechanical design
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.
AS 1824.2—1985, Insulation coordination, Part 2: Application guide.
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
Limit State Design Worked Examples
Basic Formula for Bending Moment Loads
PZ
TX
TX θ/2
θ/2
FT
=
PZ x D x W d
FT PZ D Wd TX
θ
= = = = = =
+
2 T X sin
force on the conductor wind pressure conductor diameter wind span horizontal tension structure deviation angle
θ 2
11.5.1
Pole Tip Load Calculation
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
(Load from earthwire)
2.4m 1.5m
d1
1.5m
F2
(Load from A Phase)
F3
(Load from B Phase)
F4
(Load from C Phase)
d2 d3 Fwφ
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
Fwφ 2
θ 2
900 x 0.009 x 180 + 2 x 1.25 x5000 x sin 10
3628 N 900 x 0.0188 x 180 + 2 x 1.25 x13000 x sin 10
= Fwφ
⎛ d + d3 + d4 ⎞ ⎟⎟ + F2, 3, 4 ⎜⎜ 2 d1 ⎠ ⎝
PW x OD x Wd
=
F2 , F3 , F4
+
=
8688 N Pwφ x OD x d 1
= =
1300 X 0.4 X 17.4 9048 N
F1
Tip Load =
=
+
⎛ d + d3 + d4 ⎞ ⎟⎟ + F2,3, 4 ⎜⎜ 2 d1 ⎝ ⎠
⎛ 15 + 13.5 + 12 ⎞ 3628 + 8688 ⎜ ⎟ + 17.4 ⎝ ⎠
Fwφ 2
9048 2
= 3628 + 20221 + 4524
= 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
Consideration for Stayed Pole A stayed pole should be designed to meet the following conditions: (1) Poles should be self supporting under every day load conditions without stay (should not suffer failure due to loss of stay) Everyday load = 16 kN Component strength factor for wood pole = 0.72
Ultimate strength of pole to meet everyday load = 22 kN (2)
If ground stay used and attached to top of pole Ultimate tip load due to wind load = 28.4 kN Angle of stay = 45 degrees Tension in stay = 28.4 * 1.414 = 40 kN Component strength factor for stay = 0.7 Ultimate strength of stay = 57 kN – select SC/GZ stay of 19/2.75 Compressive load in pole due to stay = 28.4 kN Compressive strength of wood pole with 300 mm dia is typically around 250 kN Ratio of compressive load to compressive strength = 11% Ultimate strength of pole to allow for stay load = 20 * 1.11 = 22 kN
STEEL POLE Steel pole component strength factor = 1.0 Ultimate Strength of Steel Pole = 28.4 / 1.0 = 28.4 kN
COMPARISON TO WORKING STRESS METHOD Pole height Earth wire Conductors Line deviation Wind span Average pole OD Wind pressure =
F1
+ 2 TX sin
θ 2
=
500 x 0.009 x 180 + 2 x 2700 x sin 10
=
1747.7 N 500 x 0.0188 x 180 + 2 x9000 x sin 10
= N
=
Fwφ
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 Pwφ x OD x d1
=
750 X 0.4 X 17.4
=
5220 N
F1
+
⎛ d + d3 + d4 ⎞ ⎟⎟ + F2,3, 4 ⎜⎜ 2 d1 ⎝ ⎠
15 + 13.5 + 12 ⎞ ⎟ + 17.4 ⎝ ⎠
⎛ = 1747.7 + 4817.7 ⎜
= 1747 7 + 11213 6 + 2610 = 15.6 kN SELECTION OF POLE
WOOD POLE Maximum Working Load on Pole = 15.6 kN
Fwφ 2
5220 2
Distribution Worked Example 2 Determine the required pole loads and foundation size for an 11 kV/415 V line in an urban area. Consider a 12.5 m wood pole on a 15° line deviation with a ruling span (RS) of 45 m. Neighbouring spans are 40 m and 55 m on level ground. The LV ABC conductor is strung to a tension to approximate the conductor sag in a span of 45m at 15°C. NOTE: Although the example is based on a timber distribution pole, the structural design principles are similar for other materials or support types.
DESIGN DATA 1200
1200
11 kV Conductor type: 200
400
19/3.75 AAC (Pluto) to AS 1531 strung at 5% of CBL at 15°C. Conductor Pluto
Dia
Mass
Area 2
Mod of E Exp Coef
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:
1.2 m left, 10.2 m above ground
Conductor 2:
above top of pole, 10.6 m above ground
Conductor 3:
1.2 m right, 10.2 m above ground
8700
415 V Cable type: 4 × 95 mm2 LV Aerial Bundled Cable (ABC) to AS/NZS 3560 and strung at 7% of CBL at 15°C. Conductor 4/95 ABC
Dia
Mass
Area 2
Mod of E Exp Coef
2300
CBL
(mm)
(kg/m)
(mm )
(MPa)
(/deg C)
(kN)
38.4
1.35
380
56000
0.000023
53.2
415 V Cable position: 0.225 m left, 8.7 m above ground
Pole details: Mixed Australian hardwood classified to AS 1720.1—1997 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 condition—EDT (i.e. every day tension) and for short duration load condition—MWT (i.e. maximum wind tension). 11 kV Conductor load conditions (RS = 45 m)
Load
Everyday load condition (Clause 3.3.2.3) Temp. = 15°C, Wind = 0 kPa (EDT)
Ft = 1.60 kN
Sustained load condition (Clause 3.3.2.2) Temp. = 5°C, Wind = 0 kPa
Ft = 1.79 kN
Short duration load condition (Clause 3.3.2.1) Temp. = 15°C, Wind = 0.9 kPa (MWT)
Ft = 4.58 kN
Intact conductor tension (Ft ) under average wind (Clause 3.6.1) Temp. = 15°C, Wind = 0.5 kPa
Ft = 2.96 kN
Failure containment loads (Fc ) (Clause 3.7.1) Temp. = 15°C, Wind = 0.24 kPa
Fc = 2.01 kN
415 V Cable load condition (RS=45 m)
Load
Every day load condition (Clause 3.3.2.3) Temp. = 15°C, Wind = 0 kPa (EDT)
Ft = 3.72 kN
Sustained load condition (Clause 3.3.2.2) Temp. = 5°C, Wind = 0 kPa
Ft = 4.16 kN
Short duration load condition (Clause 3.3.2.1) Temp. = 15°C, Wind = 0.9 kPa (MWT)
Ft = 9.32 kN
Intact conductor tension (Ft) under average wind (Clause 3.6.1) Temp. = 15°C, Wind = 0.5 kPa
Ft = 6.23 Kn
Failure containment loads (Fc ) (Clause 3.7.1) Temp. = 15°C, Wind = 0.24 kPa
Fc = 4.47 kN
Ultimate strength limit state (Clause 3.3.1) Maximum wind load (from any direction) is given by— φRn > Wn + 1.1G s + 1.25G c + 1.5Ft Capacity of 11 kV conductor
Determine φRn Strength factor φ = 0.7 from Table 3.1 Rn
=
31.9 kN
φRn
=
22.3 kN
Conductor short duration load (MWT) = 6.87 kN, therefore for each 11 kV conductor, capacity: 22.3 > 6.87, i.e. φRn > load is satisfied. Capacity of 415 V cable
Determine φRn
Strength factor φ = 0.7 from Table 3.1 Rn
=
53.2 kN from AS/NZS 3560.1 (CBL for 4 × 95)
φRn
=
37.24 kN
ABC Short Duration Load Condition (MWT) for 415 V cable = 13.98 kN Capacity: 37.24 > 13.98, i.e. φR n > load is satisfied. Pole capacity
Determine φRn Strength factor φ = 0.5 (from Table 3.1) to be applied on modulus of rupture determined from AS 1720.1 φM
=
φk1 [f’b Z] (all other kmod factors taken as 1.0)
k1
=
1.15 for MWT, i.e. φ × k1 = 0.575
and k1 =
0.57 for EDT , i.e. φ × k1 = 0.285
using
NOTE:φ capacity factor depends on grading methodology and support importance.
Pole capacity in bending taken as equivalent tip load: φRn
MWT
=
(0.575 × 50 × 103 × Z) / 10.2 = 17.71 kN and
φR n
EDT
=
(0.285 × 50 × 103 × Z) / 10.2 = 8.78 kN
where Z = πD 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
=
4.64 × 4.8 + 0.032 × 10 + 2 × 0.029 × 10.2 + 0.029 × 10.6 + 2 × +0.8 × 10.6 + 1.64 × 8.7
=
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—
For each 11 kV conductor:
Gc
=
0.27 kN
For 415 V cable:
Gc
=
0.63 kN
Transverse load due to Ft for each 11 kV conductor = 2 × T 15C,0.9kPa × sin(15 /2 ) = 1.2 kN Transverse load due to Ft for 415 V cable = 2 × T15C,0.9kPa × sin(15 / 2) = 2.1 kN The total pole base moment: The equivalent ultimate load at the top of pole: BMtot = =
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
The equivalent ultimate pole tip load = 145.87/10.2 = 14.3 kN Capacity: 17.71 > 14.3, i.e. φRn > load is satisfied Similar loads can be calculated for failure containment, maintenance and serviceability conditions. NOTE: It is advisable where designers use standard supports containing stay(s) that the structural behaviour is confirmed through the use of a non-linear design program.
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 φ = 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.
Distibution Worked Example 3 A limited number of conductor loads are calculated in this example to illustrate the development of conductor tensions using the method given in Appendix A. Determine the conductor loads for a suspension structure in a rural area on level ground. Consider an average conductor height of 30m above ground with no line deviation and a ruling span of 300 m. Use wind and weight spans of 285m within a tension section of 2400 m. The conductor is AAAC (Fluorine) with diameter = 9 mm, weight = 0.135 kg/m and CBL = 11.8 kN. The line is in terrain category 2.5 of Region B and the wind non-directional. Use a RP of 50 years (LR = 1 as per Table A.1).
Conductor Tensions for 7/3.00 AAAC (Fluorine) strung at 20% CBL at 15°C (Ruling span of 300 m) Load condition
Load
Everyday load condition (Clause 3.3.2.3) Temp. = 15°C, Wind = 0 kPa
Ft = 2.36 kN
Sustained load condition (Clause 3.3.2.2) Temp. = 5°C, Wind = 0 kPa
Ft = 2.55 kN
Short duration load condition (Clause 3.3.2.1) Temp. = 15°C, Terrain category = 2.5, mean conductor height = 8 m, Height multiplier Mz,cat = 1.06, Mt = 1, Md = 1 (AS/NZS 1170.2, Section 3) Regional wind speed V50 = 44 m/s
Ft = 7.00 kN
Design site wind speed = 44 × 1.06 = 46.64 m/s Dynamic wind pressure = 1.305 kPa SRF = 0.5 (for a tension section of 2400 m) Ultimate wind pressure on conductor for tension calculation = 1.305 × 0.5 = 0.653 kPa Failure containment loads (Clause 3.7.1) Temp. = 15°C, Wind pressure= 0.24 kPa
Fc = 3.79 kN Ft = 3.79 kN
NOTE: The conductor loads below exclude the weight of insulators and ancillaries.
Ultimate conductor loads
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
Failure containment loads
From Clause 3.7.1 failure containment limit state is given by— 0.25Wn + 1.5Ft + 1.1Gs + 1.25Gc + 1.2Fb For each conductor the contribution is— 0.25Wn = 1.5Ft
=
0.25 × 1.305 × 285 × 0.009 × 0.666 = 0.557 kN 1.5 × 3.79 = 5.69 kN
1.25G c =
1.25 × 0.135 × 285 × 9.81/1000 = 0.47 kN
1.2Fb
1.2 × 3.79 × 0.45 = 2.05 kN
=
(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
SWING ANGLE CALCULATIONS CALCULATE THE SWING ANGLE OF OXYGEN cONDUCTOR SUBJECTED TO 500 PA WIND:
WIND PRESSURE: 500 PA CONDUCTOR WEIGHT: 0.925 KG/METRE CONDUCTOR DIAMETER: 23.8 MM WIND SPAN: 300 M WEIGHT TO WIND SPAN RATIO: 0.7 TRANSVERSE FORCE FT = 500 X 0.0238 X 300 = 3570 N VERTICAL FORCE FV = 0.925 X 9.806 X 300 X 0.7 = 1905 N SWING ANGLE = ARCTAN (FT / FV) = BLOW OUT CALCULATIONS (SIMPLIFIED PROCEDURE)
CALCULATE THE BLOW OUT OF OXYGEN cONDUCTOR ON A 300 M SPAN SUBJECTED TO 500 PA WIND: SWINGING INSULATOR LENGTH = 1.5 M FROM A SAG TENSION CALCULATION, INCLINED SAG AT 500 PA WIND = 12 M TOTAL INCLINED LENGTH = 13.5 M HORIZONTAL DISPLACEMENT = SIN (SWING ANGLE) X TOTAL INCLINED LENGTH =
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: •
Introduce a vertical spacing between conductors,
•
Increase the horizontal spacing between conductors,
•
Insert additional poles midspan between conductors,
•
Install midspan spacers between conductors,
¾ Reduce protection clearing times
To determine whether a line is susceptible to conductor clashing the calculations can be performed with formula provided in the following EPRI publication, Bathold L.O., Clayton R.E., Grant I.S., Longo V.J., Stewart J.R & Wilson D.D., Transmission Line Reference Book: 115-138 kV Compact Line Design, EPRI, 1978.
12 ROUTE SELECTION PROCESS
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
-
Use of non specular finish conductor Painting of structures (in particular poles) to match the existing landscape
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.
13 LAYOUT DESIGN PROCESS
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.
Formatted: Indent: Left: 18 pt
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.
Formatted: Bullets and Numbering
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
3
L RS
=
Where:
L = length of each span in a tension section LRS = Ruling Span
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.
Assumptions for Ruling Span With RS, the horizontal tensions in the left and right spans are assumed to be those of their ruling spans.
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.
Detailed design criteria This section describes the many design criteria that can be used and checked. Criteria can be developed in standard libraries to be shared among various projects or they can be developed only for a specific project. Weather cases Many strength and serviceability (clearances) criteria assume that the line is subjected to a given combination of wind, ice (or snow) and temperature. Such a combination is defined herein as a "weather case". All cable sag and tension calculations, and consequently all loads and clearance calculations, are made for designated weather cases. All weather cases which will be used in a particular design must be described. A weather case table typically includes a group of weather cases for checking the strength of the structures, a group for checking various geometric clearances (to ground, blowout, between phases, swings, etc.), and a group for checking ground wires and conductors tensions. It also includes the weather case assumed to cause creep, the heavy load case which potentially causes permanent stretch of the various cables, and various weather cases needed for displaying the cables at various temperatures.
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 .
13.1 Pole Locations in Traffic Corridors
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.
13.3 Waterway Crossings
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 ????
13.4 Co-ordination with other Services
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.
This may require consideration of: •
• • •
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
13.7 Ruling Span The Ruling Span means that level dead-end span in which the behaviour of the tension closely follows that of the tension in every span of a series of suspension spans in a tension section. A tension section is the length of line between 2 termination structures. The ruling span is often called the mean equivalent span. The formula for ruling span is:
∑L ∑L
3
L RS Where:
=
L = length of each span in a tension section LRS = Ruling Span
14 COST OF OVERHEAD LINE (BY COMPONENTS) The cost of an overhead line can be broken down into different component costs: conductor, earthwire, insulators/fittings, towers, foundation, and engineering. Each component includes material and erection (construction). The breakdown of transmission lines into component costs, which is averaged internationally is given in Table 4.
TABLE 4 -TYPICAL BREAK DOWN INTO COMPONENT COSTS (All figures are % of total line costs) Components
< 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
15 GUIDELINES FOR POLE LOCATION Normal Carriageway Use Poles shall be setback from carriageways to prevent them from being hit by a vehicle normally traversing the carriageway and to provide clear vision for the driver.
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.
15.1 Acceptable Location of Poles in Road Corridors 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. Alternatively, guidance to setbacks and barriers are covered in the following Standards. i) ii) iii)
Australian Standard AS1158.1.3. Austroads Rural and Urban Road Design. Road Safety Barrier Design AS/NZS 3845.
15.2 Special Considerations for Slip based poles Slip based poles should not be used in areas with high pedestrian based activity. The slip based poles are unsuitable for these areas as these poles are deliberately designed to fall over after vehicle impact to lessen the damage to the vehicle occupants. Having these poles fall over in high pedestrian areas introduces an unacceptable risk. High pedestrian areas are schools,
shopping centres, major entrances/ exits to sporting or entertainment venues, and train or bus stations entrances/ exits, .
15.3 Aerial Lines in the Vicinity of Aircraft Lines Near Takeoff and Landing Areas Where lines are installed near takeoff and landing areas for aircraft, the structures shall not interfere with the takeoff and landing of aircraft. That is, for fixed wing aircraft the poles shall not enter the obstacle restricted area or the obstacle limitation surfaces (OLS) and for helicopter landing areas the poles shall not enter final approach and takeoff (FATO) areas. OLS and FATO limits may be ignored where there are other permanent taller structures in the vicinity of the new line, such as trees or radio masts. OLS limits are defined in Civil Aviation Safety Regulations (CASR) Part 139 – Aerodromes. FATO limits are defined in Civil Aviation Advisory Publication 92–2 (1) Guidelines for the establishment and use of helicopter landing sites. Military sites have take off and landing restrictions that are different to civilian requirements. The take off and landing restrictions can be obtained from the relevant site. The standards do not have limitations on pole placements near hot air balloon take off and landing area.
Lines in Areas Other Than Takeoff and Landing Areas In areas, other than takeoff and landing areas, overhead lines shall be located to avoid possible interference with normal aircraft flight paths. In areas where overhead lines may be significantly higher than the pole height, which are known flight areas, permanent markers should be fitted. Areas that may have conductors higher than some of the poles are in valleys, across water ways and near hills.
Marking of Powerlines in Proximity to Airstrips Marking of power lines is required in close proximity to airstrips and on spans with exceptionally high ground clearance across deep valleys. Consideration should also be given to the marking of power lines in areas where regular low-level flying operations take place. Guidance on the marking of power lines in Australia for the purposes of air navigation is provided in : AS 3891 Air Navigation – Cables and their supporting structures – Mapping and marking - Part 1: Permanent marking of overhead cables and their supporting structures - Part 2: Marking of overhead cables for low-level flying Suggested changes and additions to exiting Section 14? In general aerial lines shall not be installed so as to cause a hazard with aircraft.
15.4 Country Line Road Crossings It is not uncommon in country areas for lines to fall and the line to be left suspended above the ground. That is, the line is left suspended on a fence or held up with part of the failed pole. There is also a risk that this situation could be in place for longer time periods than in metropolitan areas. The longer time periods can be caused by a line patrolworker taking longer to find the fault due to distance or terrain or the general public not being in the vicinity of the fault to be able to see and report the problem. When a suspended line is in a remote area, across a high-speed road and the line is of low visibility the consequences could be catastrophic for the occupants of a vehicle impacting the wires. Strain poles either side of the road would increase the security of the line but it would not eliminate the possibility of the line falling and being left suspended above the road. Low visibility lines are typically SWER one and two bare wire systems. To reduce the chance of a collision between a motorist and a suspended line consideration shall be given by the designer to increase the visibility of bare single-phase overhead lines that cross remote high speed roads. Increased visibility devices should be used on roads where speed limits are equal to or above 90kmh. Increased visibility can take the form of pre-form fluorescent wraps or marker balls. The above practice is not required for three phase bare, ABC, CC or CCT installations as they are more visible. The above practice is not required on low speed country roads, as these tend to be near populated areas or where the driver will have a greater opportunity to break in time to avoid collision with the wire. The above practice is not required in metropolitan areas.
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.
Over Crossing Markers Where inspection of overhead lines by aircraft is conducted, supports should be marked each side of any over crossing.
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: •
To achieve a balance between environmental responsibilities and ensuring a safe, reliable and economical electricity supply to our customers.
•
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.
Vegetation Clearance Zones Figure …shows the vegetation zones surrounding an overhead powerline. These zones are described as: Clearance Zone - is the space that must be clear of vegetation at all times, including the period between trimming cycles.
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
Figure .. Vegetation Clearance Zones surrounding Overhead Line
Clearances to vegetation are generally established by regulations and industry guidelines in various jurisdictions. Additional clearing may be needed to improve the reliability of the overhead line. Typical clearance distances for a high reliability lines operating up to 33 kV are shown in Table 1.
Typical clearance distances for low voltage Aerial Bundled Cable and Insulated Service Cable are shown in Table 2.
Special Considerations for Transmission Lines On Transmission Lines special consideration should be given to extend the vegetation clearing to meet the higher levels of security and reliability for the line. The extended clearance may include clearing to the sky (refer Figure ..) and allowance for blow out of the conductors in the mid sections of the line.
17 LIST OF AVAILABLE LINE DESIGN PROGRAMS Structural Programs: • • • • • • • • • •
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
COMMENTARY ON APPENDIX B – WIND LOADS
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
Wind Regions for Australian Design Wind Gust Types
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 line’s 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
In Clause B3 reference is made to wind direction multipliers Md as provided in Table 3.2 of AS/NZS 1170.2 being taken as 1.0 to provide for multiple changes in direction of the route of overhead lines. In some cases it could be argued that where a line route is in a predominate direction for its entire route and the line design is unique for that line only, that consideration be given for a lower value direction multiplier. However line designs once created usually have repeat applications on other line projects which could have multidirectional characteristics and extreme caution is required if reduced values of Md are used. Cyclonic wind amplification factors Fc and Fd provided in AS/NZS 1170 Clause 3.4 are to be taken as 1.0 for all overhead lines, based on performance of overhead lines in cyclonic areas over time. These factors are provided in AS/NZS 1170.2 to apply additional security due to some uncertainty with wind velocities in the light of the recent incidence of several major Category 5 events. Performance of major transmission lines in these regions over the last 50 years has been very good, despite some structure failures occurring. Distribution line network failures in such extreme events occur regardless of magnitude of wind velocities primarily as a result of airborne vegetation and building debris. Hence the value of 1.0 has been applied for all lines in these areas. B4. Downdraft wind regions (Australia Zone II and Zone III and New Zealand Zones Region A 7 ) B4.1 Downdraft Winds The standard provides for all structures to be designed for V50 3 second gust regional wind speeds as defined in AS/NZS 1170.2. Higher or lower security levels of line design are then adjusted from this value using Security Multipliers from Section 6.
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
Geographic region (1)
New Zealand
I, II, III, IV, V, VI, VII
Australia
Basic regional pressures (kPa) for limit states
W
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.
B5.1 Wind Pressures on Lattice Steel Towers
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.
B5.2 Wind Pressure on Poles Many utility poles have ancillary items attached to them either in a temporary or permanent capacity. This can include banner support brackets, banners, cable television boosters, and communications cables. Where these items are added at some time after the initial overhead line was constructed, support structures need to be reviewed to ensure that public safety margins are not jeopardised. B5.3 Wind Forces on Conductors
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.
19 COMMENTARY ON APPENDIX D - GUIDELINES ON SERVICE LIFE OF OVERHEAD LINES (Informative) While this is an informative appendix, the information presented is drawn from a number of industry reference groups and research experts and reflects best estimates for general application in design of overhead lines for a range of construction types. Section 6 –Table 6.1 sets out security levels and design working life combinations for the selection of security load multipliers to be applied to design loadings. The selection of the appropriate Design Working Life for each design suite of supports and type of support can have a significant influence on the reliability of the structure and public safety. The information provided is considered conservative for each exposure condition assumed. Clause D1 GENERAL of the standard defines the Design working life or service life of a structure as the period (generally in years) over which it will continue to serve its intended purpose safely, without undue maintenance or repair disproportionate to its cost of replacement and without exceeding any specified serviceability criteria. This recognizes that cumulative deterioration of the structure over time will occur, due to ‘wear and tear’ or environmental effects. Therefore, in order to maintain structural integrity within adequate design margins adequate maintenance and possible minor repairs will be required from time to time to maintain the structure in a safe and useable condition over its service life. The design life, or target nominal service life expectancy, of a structure is dependent on a number of variable factors. The information contained in this Appendix is given as a reasonable basis for the economic evaluation of alternative support systems; the selection of a particular structure type for given site conditions; the detail design of a particular structure; or the selection of suitable materials or protective treatment. Structures and fittings located within 1.0 km of the sea will be subjected to more severe exposure and would normally require either special protection or a shorter service life. Experience in these coastal regions suggests that metallic fittings will be the weakest link over time and may need to be replaced more than once during the economic life of the structure. Clause D2 SUGGESTED NOMINAL SERVICE LIFE and Tables D2 and D4 provide recommended nominal service lives for steel, concrete and timber pole structures and lattice steel towers based on a range of ‘above-ground’ exposure classes as set out in Table D1.
TABLE D1 ABOVE-GROUND ENVIRONMENTAL EXPOSURE CLASSIFICATION (AUSTRALIA) Climatic zone (see Figure D1) Arid
Temperate (4)
Tropical
Geographic region (1) Inland Near-coastal Coastal Inland Near-coastal Coastal Inland Near-coastal Coastal
Industrial proximity (2)
Exposure class (3)
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
—
C
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
60–100+
100+
100++
100+
A2
25–60
60–100
75–100+
80–100
B1
12–25
25–50
35–75
60–80
B2
8–25
15–50
35–75
50–60
C
( 3)
3–12
(6)
6–25
(6)
9–35
(6)
50
(4)
TABLE D4 SUGGESTED RANGE OF NOMINAL SERVICE LIFE OF TIMBER POLES Zone (see Figure D3)
Service life expectancy (years) H5 treated timber to AS 1604
Desapped untreated timber
1
Class 1 45–55
Class 2 35–45
Class 3 25–35
Class 4 40–50
Class 1 25–35
Class 2 15–25
2
50+
50+
30–40
50+
30–40
25–35
3
50+
50+
40–50
50+
50+
30–40
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.
20 COMMENTARY ON APPENDIX F - TIMBER POLES
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
Softwood (S) or Strength group Natural durability hardwood (H) (Unseasoned) ratings
Species brand
box, coast grey
H
S1
1
CB
gum, grey
H
S1
1
GG
ironbark, broad- leaved red
H
S1
1
BU
ironbark, grey
H
S1
1
GI
blackbutt
H
S2
2
BB
box, grey
H
S2
1*
GB
box, white
H
(S2)
2*
WX
box, white topped
H
S2
2*
WT
gum, poplar
H
(S2)
3*
PG
gum, salmon
H
(S2)
3*
SA
gum, spotted
H
S2
2
SG
ironbark, narrow-leaved red
H
S2
1
NI
ironbark, red
H
S2
1
RI
mahogany, red
H
(S2)
2
RM
mahogany, southern
H
S2
2
SM
mahogany, white
H
S2
1
WM
stringybark, blue-leaved
H
S2
3*
SL
stringybark, silvertop
H
S2
3
SS
Tallowwood
H
S2
1
TW
ash, silvertop
H
S3
3
ST
blackbutt, New England
H
S3
2
NA
bloodwood, brown
H
S3
2*
BD
(Continued)
Standard trade common name bloodwood, red
Softwood (S) or Strength group Natural durability hardwood (H) (Unseasoned) ratings H
S3
1*
Species brand RW
box, brush
H
S3
3
BH
box, red
H
S3
2*
RX
box, yellow
H
S3
1
YB
gum, southern blue
H
S3
3
BG
gum, forest red
H
S3
2
FR
gum, Maiden's
H
S3
3*
MG
gum, mountain grey
H
S3
3
MT
gum, rose
H
S3
3
RO
gum, Sydney blue
H
S3
3*
SY
peppermint, broad- leaved
H
S3
3
BT
satinay
H
S3
1
S
stringybark, brown
H
S3
3
BS
stringybark, messmate
H
S3
3
MS
stringybark, red
H
S3
3
RS
stringybark, white
H
S3
2
WS
stringybark, yellow
H
S3
2
YS
turpentine
H
S3
1
TP
ash, alpine
H
S4
4
AA
ash, mountain
H
S4
4
MA
brownbarrel
H
S4
4
BL
gum, manna
H
S4
4
MN
gum, mountain
H
S4
4
MO
gum, yellow
H
(S4)
1
YG
peppermint, narrow-leaved
H
S4
3
NL
peppermint, Sydney
H
(S4)
3
SP RR
gum, river red
H
S5
2
peppermint, black
H
(S5)
3*
BP
pine, cypress white
S
S5
1*
WC
pine, slash
S
S5
4
PS
fir, Douglas (Oregon)—North America
S
S5
4
DF
fir, Douglas (Oregon)—elsewhere
S
S6
4
DF
pine, Caribbean
S
(S6)
4
PB
pine, hoop
S
S6
4
HP
pine, loblolly
S
S6
4
PL
pine, maritime
S
(S6)
4
PM
pine, radiata
S
S6
4
PR
pine Corsican
S
(S7)
4*
PC
(Continued)
Softwood (S) or Strength group Natural durability hardwood (H) (Unseasoned) ratings
Standard trade common name pine, patula
S
(S7)
pine, ponderosa
S
pine, Canary Island
S
pine, long-leaf
S
Species brand
4*
PP
(
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
See AS 5604 for definitions of timber natural durability ratings.
2
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.
3
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
Assumed critical cross section for design dgl
Refer tabulated Ultimate bending moment capacities Tables F4.1 F4.2 and F4.3 L GL
Butt
L
Pole planting depth see comments on Appendix L
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
Characteristic bending strength (MPa)
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
4
k 20 immaturity factor applied for poles of diameter less than 200 mm.
5
φ = 0.90, ‘normal’ use; change to 0.75 for critical importance.
6
k 1 = 1.00; use 0.57 for permanent loads.
7
k 21 = 1.00, shaving factor (in critical zone, i.e., −1 m < GL < +2 m).
8
k 22 = 0.85, steam processing—assumed for all CCA poles.
9
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
Characteristic bending strength (MPa) 40
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.
2
φ = 0.90, ‘normal’ use; change to 0.75 for critical importance.
3
k 1 = 1.00; use 0.57 for permanent loads.
4
k 21 = 0.85, shaving factor (in critical zone, i.e., −1 m < GL < +2 m).
5
k 22 = 1.00, no processing.
6
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
Characteristic bending strength (MPa)
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.
2
φ = 0.90, ‘normal’ use; change to 0.75 for critical importance.
3
k 1 = 1.00; use 0.57 for permanent loads.
4
k 21 = 0.85, shaving factor in critical zone (−1 m < GL < +2 m).
5
k 22 = 0.85, steam processing—assumed for all CCA poles.
6
k d = 1.00, preservative treated Eucalypt, 25 year expected maintenance free service life.
21 COMMENTARY ON APPENDIX I - CONCRETE POLES Design of Concrete Poles Concrete poles produced in Australia and New Zealand are either designed as a normal reinforced concrete cast product based on calculated design or as a centrifugally spun cast product that has a proprietary design correlated and supported by extensive testing. Some pole designs have prestressed tendons or partially prestressed tendons that provide permanent compression of the pole element under most loading conditions and result in most cases in a more durable pole product. The design provisions of the standard are general application clauses covering all types of design, but more specifically to poles designed by calculation as set pout in Clause I 3. The most important requirements for concrete pole designs apart from strength are concrete durability and control of deflections and related crack widths. Clause I 4.2 Deflection and rotation – identifies the potential problem but it is a significant issue on stayed poles or poles subjected to permanent bending moments. Even though bending stresses may be low, concrete strain/creep over time can result in crack widths that may not effectively autogenous self seal. This type of cracking may take 6 – 9 months of exposure to permanent load to develop discernable creep related cracking and field experience indicates that the creep will continue and cracks widen further with time with the potential for corrosion of exposed steel reinforcement. Deflection of pole elements with permanent bending stresses should be checked and assessed for potential cracking that may exceed the specified limits. Clause I 4.3 Crack width sets out that crack widths at the serviceability limit state shall not exceed 0.25 mm. All concrete will develop barely measurable minute cracks and most self seal. Crack widths from handling stains and construction or other flexural loadings <0.25mm are acceptable for average exposure conditions In addition Appendix D of the Standard also sets out the following crack width recommendations in relation to design service life requirements for a range of general exposure classifications: (1)
Width <0.3 mm
Exposure Classifications A1, A2, B1.
(2)
Width <0.2 mm
Exposure Classification B2.
(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
In particular it sets out the following requirements: 1. Load testing of prototype poles may be used as an acceptable alternative to strength calculations to verify flexural bending and shear capacity strengths for pole type elements. 2. Routine Sample poles shall be tested to determine whether structurally similar poles are deemed to comply with the requirements for strength and serviceability of this Standard. Deflection characteristics of repetitive sample pole tests compared to prototype test deflections provides a useful tool for monitoring quality of pole product manufacture.
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.
Pole Manufacture Related Design Issues
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.
22 APPENDIX L - STRUCTURE FOOTING DESIGN AND GUIDELINES FOR THE GEOTECHNICAL PARAMETERS OF SOILS AND ROCKS
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.
L3 FOOTING DESIGN OF DIRECTLY EMBEDDED OVERHEAD LINE POLES FOR LATERAL LOADS AND MOMENTS The Brinch Hansen methodology provided in this clause and other methods referenced such as Broms ASCE 1964, while theoretically applied in some areas for major pole or single bored pier footings they are not commonly used for directly embedded pole type distribution overhead line construction, as they require a level of engineering that is not always available to that sector of the electricity supply industry and in particular to distribution lines. In addition simple design methods have been in use for distribution pole overhead lines throughout Australia and New Zealand and overseas for many years and these overhead lines have performed well over time. This suggests that either the design loadings have not generally reached the failure limit state at a particular structure such as to cause failure or that the footing design methods adopted have been conservative.
There are three commonly used methods 1. American Society of Agricultural Engineers ANSI/ASAE EP486.1 OCT 00 Shallow Post Foundation Design and as approved OCT 2000 by American National Standards Institute. For the simple unrestrained top pole the following pressure diagram refers.
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 =
b = effective width of the pole in the soil perpendicular to the direction of movement,( m) d = minimum pole embedment depth to resist applied forces with a maximum soil pressure of S ( m) Ma= moment applied to foundation at ground surface, kN·m S = allowable lateral bearing soil pressure, per unit of depth including increases, kPa/m Va = shear force applied to foundation at ground surface, kN
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
L
Assumed critical cross section for design dgl
Ground level 200mm dg
Refer tabulated Ultimate bending moment capacities Tables F4.1 F4.2 and F4.3 L GL
db
Pole planting depth see comments on Appendix L
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
= Min[(1 + 0.1 × h r) × (d g/330),4.8] for h r ≥18
. . . E2
where L GL = min. embedment depth, in metres
hr
= height from the ground line to the conductors, in metres
d g = diameter of the pole at the ground line (GL), in metres
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)
6
7.5
9
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
3 ASCE Method (EX AS/NZS 4676) This method also assumes soil pressures increasing linearly below ground surface and calculation of embedment depth is based on ultimate limit design principles and utilises soil properties for generalised cases likely to be experienced in the field.
The assumptions made are : 1. the centre of rotation of the footing as located at two thirds of depth below the ground surface; 2
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
3.1.1 Bearing strength 3.1.1.1 Serviceability limit state Table I1 has been prepared using a simple broad classification of soil types, with bearing strengths based on degree of firmness or resistance to indentation. This can be readily assessed on site by simple standard penetrometer test (AS 1289.F.3.2) at the appropriate depth. The boundaries between the classes are in fact quite arbitrary but correlate well with permissible bearing stress values quoted in the technical literature.
TABLE I1 BEARING STRENGTH OF SOILS AT THE SERVICEABILITY LIMIT STATE Class
Very soft
Soil description
Soft
Silty clays and sands; loose dry sands f b ≤ 60
Strength (f b ) kPa
Wet clays; silty loams; wet or loose sands 60 < f b ≤ 100
Firm
Very firm
Hard
Damp clays; sandy clays; damp sands
Dry clays; clayey sands; coarse sand s; compact sands
Gravels; dry clays
100 < f b ≤ 150
150 < f b ≤ 240
240 < f b
The above values are based on foundation deformations of approximately 12 mm under serviceability loads on building structures. For poles supporting services that are sensitive to displacements at their supporting points (e.g. microwave antennas), this degree of deformation might be inappropriate. Therefore, suitable reduction of these values may be necessary. This may be achieved by increasing the embedment depth, or the footing diameter, or both, which will reduce the bearing pressures and, consequently, the deformations.
NOTE:
3.1.1.2 Strength limit state The behaviour of soils under high levels of stress can vary from plastic for very soft soils to brittle for very hard materials such as rock. Consequently ultimate compressive strengths can be reliably determined only for some rocks and certain very stiff cohesive soils. In these circumstances, it is more practicable to adopt the ‘permissible’ bearing strength concepts used for the serviceability limit state and extend them by suitable factoring. Therefore, the bearing strength for the strength limit state (fbu) should be taken as 1.5 times the value obtained from Table I1. 3.2 Shear strength For soils with fb less than 150 kPa, the shear strength may be determined directly in a laboratory shear-box test or by the vane test in the field. The values obtained from such tests indicate an average shear strength value of about half the bearing strength value obtained from a bearing plate test. Because there are a large number of variables involved, there is a wide scatter of results although the soils may exhibit the same bearing strength. Consequently, the shear strength of a soil should be taken as not greater than 0.4 fb where fb is the value obtained from Table I1. 3.3 FOOTINGS AND EMBEDMENT DEPTH IN SOILS 3.3.1 Design Method Based on the above assumptions, the embedment depth (D) may be determined from the following equation:
D=
3.6 H R + 12.96 H R2 + 16.2 CM 2C
. . . I3.2(1)
where C
=
fbu.b for ultimate limit state, or fb .b for serviceability limit state fb
=
the nominal maximum bearing strength of the foundation material (kPa)
fbu
=
1.5fb
b
=
the effective width of the footing, projected on a plane
perpendicular to the direction of the resultant horizontal force acting on the pole (m) M
=
the overturning moment acting on the pole at ground level (kNm)
=
HR .h r HR
=
the resultant of the horizontal forces acting on the pole (kN)
hr
=
the height above ground level at which HR acts (m)
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
=
the sum of the vertical components of the guy or stay tensions
Fv
=
the sum of the vertical forces acting on the pole from loads other than F gt
(a)
Fixed embedment depth
For this arrangement, the following assumptions are made: 1 2 3 4
The embedment depth (D) is a fixed proportion (k) of the height of the top of the pole above ground level (h p ) i.e. D = kh p . The centroid of area of the upper (breast) bearer is located at 0.3 m below ground level. The centroid of area of the lower (toe) bearer is located at 0.1 m above the bottom of the footing. The foundation pressure acting on the bearers is distributed uniformly over their contact surfaces with a maximum magnitude of 0.85 f b.
Based on the above assumptions, the reaction force on upper bearer (Rb1) is given by —
Rb1 = H R ( Khp + hr − 0.1) /( khp − 0.4)
. . . I3.3(1)
the reaction force on the lower bearer is given by
Rb2 = Rb1 − H R ; and
. . . I3.3(2)
the face areas of the bearers (Ab ) are calculated from
Ab = Rb / 0.85 f bu
. . . I3.3(3)
where the symbols are illustrated in Figure I3.2.
FIGURE I3.2 FORCES ON FOOTINGS AND FOUNDATIONS (FIXED EMBEDMENT) (AS/NZS 4676)
DERIVATION OF EMBEDMENT FORMULA
Referring to Figure I3.1 for static equilibrium: 1
The sum of the horizontal forces is zero
i.e. HR + R2 –R1 = 0 Reaction R1 =
Projected width of pole times the area of the upper pressure distribution
⎡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
HR (hr + 8D/9) –R1 (5D/9) = 0
. . . I4(1)
Expanding and multiplying throughout by 9 — 9HR hr + 8HR D –5R1 D = 0 Substituting the value from (a) for R1 gives —
9 H R hr + 8 H R D − 5 D
(4b. f bu .D) =0 9
. . . I4(2)
Multiplying throughout by –9/20 and rearranging gives—
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)
Substituting C for b.fbu and M for HR h r— D=
3.6 H R + 12.96( H R )2 + 16.2.CM 2C
. . . I4(4)
TABLES OF MINIMUM EMBEDMENT DEPTHS
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.
1
TABLE I2(A)
2
POLE EMBEDMENT DEPTHS FOR SOILS WITH f b = 150 kPa Embedment depth (D) (Note 1) m, for horizontal force (H) kN Effective height h (m)
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
2
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)
Embedment depth (D) m, for horizontal force (H) kN H = 16
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
2
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.
L2. FOUNDATION DESIGN FOR LATTICE STEEL TOWERS. This section of the standard provides basic design methods that have been used around the world over many years. These methods for the most part have been the subject of investigation and research over many years by Cigre, EPRI and post graduate research projects. The design methods provided in the standard are simple, conservative and provide a reasonable minimum standard for adoption. The basic methods have been in use for many years and have performed well and are supported by full scale and scale model load tests. There are however other methods and refinements that have evolved based on research reports. Not all are adequately supported by exhaustive testing programs due to the variable nature of the soil conditions modelled and the nature of the loads being considered. Some also imply a higher level of engineering interpretation that may have some practical difficulty in being able to be applied during construction. Such methods should be used with caution and should be correlated with the assumed soil characteristics of where the research was carried out.
23
LOW VOLTAGE AERIAL BUNDLED CABLE
1.2 general LVABC may be used as— (a)
an aerial cable suspended between two or more supports; or
(b)
a cable attached to the facades of buildings.
1.3 Aerial cable 1.3.1 Supports Mechanical support fittings, including pole fittings, strain clamps and suspension clamps, should comply with the requirements of AS 3766. (i)
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.
1.3.2 Cable tension In addition to the requirements of Section 7 the following considerations apply: (a)
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. Australia’s 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)
Supply authority access to the cable and fittings.
(f)
Notification to the supply authority in advance of modification or demolition of the facade.
1.4.1 Mechanical design Care should be taken to protect the building fabric from damage due to external influences on the cable. The cable on the facade may be either ‘tensioned’ or ‘non-tensioned’. The choice is dependent on the type of facade, the strength of the fittings and the length of straight runs. (a)
(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)
Intermediate wall supports are spaced at 500 to 700 mm intervals.
‘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)
Intermediate wall supports are spaced at 3 to 6 m intervals.
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
A
Clearance vertically from ground or path level
Minimum permissible clearances m 2.5
Comments
This should be increased if local conditions make it possible for bundle to be touched or damaged
B
Above windows and doors
0.3
C
Each side of and below windows
0.5
D
Each side of doors and balconies
1.0
E
From metallic parts of buildings, e.g. downpipes
0.05
This may be reduced to 0.2 m only where it is physically impossible to obtain 0.3 m
Whichever is wider
FIGURE 16.1 MINIMUM PERMISSIBLE CLEARANCES FOR TABLE 15.1
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
HIGH VOLTAGE AERIAL BUNDLED CABLE
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)
Self-supporting High Voltage Aerial Bundled Cable (not currently covered by an Australian Standard).
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)
maintains the outer semi-conducting insulation screen potentials at acceptable levels under all operating conditions; and
(b)
provides a defined path for any fault current.
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
COVERED CONDUCTOR SYSTEMS
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)
When attaching covered conductors to insulators, special measures should be taken to manage radio interference voltage and leakage currents, particularly in high pollution areas.
(c)
Clearance between phases may be reduced (See Clause 10.3 Note 3).
(d)
Clearance to trees may be reduced.
(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)
abrasion due to the species of tree and its growing pattern;
(ii)
frequency and strength of prevailing winds; and
(iii) operating temperature. (c)
Better performance in polluted environments.
(d)
Suitable for use in the Insulated Unscreened Conductor (IUC) system.
(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
Salt spray pollution
Industrial pollution
Open ocean
Bay, inlets and salt lakes
Acidic
Alkaline
AAC
1
1
1
3
AAAC/6201
1
1
2
3
AAAC/1120
1
1
1
3
ACSR/GZ
3
2
2
3
ACSR/AZ
2
1
2
3
ACSR/AC
1
1
2
3
SC/GZ
3
2
3
2
SC/AC
1
1
1
3
OPGW
1
1
2
3
HDCu
1
1
2
1
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)
Full or partial greasing of the conductor significantly improves corrosion resistance.
(b)
Ensure that all fittings are compatible so that electrolytic corrosion does not occur.
(c)
Insulated/covered conductor systems may provide protection against corrosion provided the conductors are completely sealed by the insulation/covering and do not provide traps for corrosive solutions nor allow ingress of moisture.
(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.
Maximum design operating temperatures The design maximum operating temperature is a function of the acceptable level of permanent loss of tensile strength (annealing) of the conductor. Annealing is caused by the heating of a material generally followed by a cooling period. During the annealing process, the material experiences a change in its microstructure and for metals, this not only results in a loss in tensile strength but also an increase in conductivity. In general, changes of conductivity will be insignificant compared with the changes of tensile strength. Isothermal annealing curves are illustrated in Figures D1, D2 and D3 for AAC 1350, AAAC/1120 and AAAC/6201 respectively. These curves demonstrate the permanent loss of tensile strength when a conductor operates at an elevated temperature. The loss of tensile strength results in increased sag. It is appropriate to establish the maximum design temperature at which a conductor can operate while maintaining acceptable levels of degradation of tensile properties. More recent research indicates that the annealing characteristics of a conductor depend not only on temperature and time of exposure but also on the diameter of the wires in the conductor. Typically the loss of strength curves shown in Figures D1, D2 and D3 will comprise a range of values for a given period with the smallest wire size suffering the greatest loss in strength and the largest size the least. The magnitude of this wire size dependence is considered, at this stage, to be of a lower order than the effect of temperature. The following comments are applicable for aluminium conductors. Copper has similar annealing properties which are not as well documented as those for aluminium, but it has less loss of strength for the same temperature. The recommended maximum temperature limit for normal operation of AAC, AAAC, and ACSR is 100°C. This permits an approximate loss of strength of 3% of the original tensile strength after 1000 hours operation at this temperature. Figures D1, D2 and D3 show that the heating period is not a major factor until this temperature is exceeded. For ratings for emergency conditions (e.g. when one circuit has to carry more than normal current for a short time), both the maximum temperature and the duration of the emergency load should be taken into account in determining the annealing of the aluminium wires. The annealing effect is cumulative. For example, if a conductor is heated to 150°C under emergency conditions for 24 hours a year for 30 years it is much the same as heating the conductor continuously at that temperature for 720 hours. For this example the loss of ultimate strength in AAC would be approximately 15%. For 30/7 ACSR the ultimate tensile strength would be reduced approximately 7%. The effect is less significant for ACSR where an increase in temperature results in a load transfer from the aluminium to the steel. The steel provides most of the strength of the conductor and is essentially unaffected by the temperature. If ratings for emergency conditions are to be applied then the combined effects of elevated temperature and sustained high conductor tension on the sag of the line should be taken into account. Practically, the tension in a line reduces with increasing temperature so the effect is less severe. For main grid transmission lines, where it is possible to control the loads in the lines to a great extent, the emergency condition rating concept may be applied. For radial transmission lines and sub-transmission lines, the maximum temperature limit of 100°C should be applied.
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 50°C to 65°C are commonly used.
FIGURE D1 PERCENTAGE OF ORIGINAL TENSILE STRENGTH FOR ALLOY 1350 vs AGEING TIME
FIGURE D2 PERCENTAGE OF ORIGINAL TENSILE STRENGTH FOR ALLOY 1120 vs AGEING TIME
FIGURE D3 PERCENTAGE OF ORIGINAL TENSILE STRENGTH FOR ALLOY 6201 vs AGEING TIME
Conductor permanent elongation Further information on designing for conductor permanent elongation is contained in the following references: Permanent Elongation of Conductors Predictor Equations and Evaluation Methods, CIGRE Electra 75. BRENNAN, G. F., Methodology for Assessment of Serviceability of Aged Transmission Line Conductors. Postgraduate Thesis, Wollongong University, 1989. DRURY, M. D. The Effect of Prestressing on Inelastic (Creep) Behaviour of Australian Made Base Overhead Conductors. Postgraduate Thesis, Wollongong University, 1993. Conductor permanent elongation is non-recoverable or inelastic material plastic deformation that is a logarithmic function of conductor stress, conductor temperature and exposure duration. Permanent elongation begins at the instant of applied axial tensile load and continues at a decreasing rate providing tension and temperature remain constant. The permanent elongation consists of, in the short term, primarily wire radial and tangential movement during the early loading period and in the longer term, primary metallurgical logarithmic creep. To compensate for conductor inelastic stretch it is necessary to carry out one or a combination of the following: a) Add a margin on the statutory ground clearance requirements. b) Subtract an allowance on the maximum design temperature. c) Prestress conductors prior to final sagging. d) Over-tension conductors. Conductor permanent elongation expressed as a function of time, temperature, conductor stress and conductor constants is given as: ε
=
kt c1σc2ec3(θ−20)
In most cases the conductor exposure period at elevated temperatures is very small relative to an everyday exposure temperature assessed to be 20°C hence the above equation may be reduced to: t
=
kt c1σc2
ε
=
unit strain in mm/km
t
=
time in years
σ
=
conductor average stress in MPa
θ
=
conductor average temperature in °C
where
k, c1, c2 and c3 are constants Conductor creep is cumulative for a given set of operating conditions of time, temperature and stress. c1
t eq ( i )
⎡ σ ( i −1) ⎤ = ⎢ ⎥ ⎣ σ1 ⎦
teq(i)
=
the equivalent time in years for unit strain at stress level σ(i)
σ(i-1)
=
the stress level in MPa associated with time interval t(i!1)
σ(i)
=
the stress level in MPa associated with time interval teq (i)
t(i-1)
=
time interval in years associated with stress level σ(i–1)
i
=
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
=
temperature coefficient of resistance in °C–1
R
=
resistivity in ohm mm at 20°C
D
=
density in g/mm3
J
=
current density in A/mm2
t
=
duration in seconds (includes reclosure times)
C
=
specific heat =
C20
=
specific heat at 20°C in Jg-1 °C-1
Ac
=
temperature coefficient of specific heat
⎧ ⎡ ⎛ T + T2 ⎞ ⎤⎫ C 20 ⎨1 + Ac ⎢⎜ 1 ⎟ − 20⎥ ⎬ ⎣⎝ 2 ⎠ ⎦⎭ ⎩
Transposing equation D1 gives D2
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 20°C) *
°C−1
0.00403
0.00390
0.00360
0.00381
0.00440
0.00360
R (at 20°C) *
Ωmm
28.3 × 10 −6
29.3 × 10 −6
32.8 × 10 −6
17.77 × 10 −6
190 × 10 −6
85 × 10 −6
D*
g/mm 3
2.70 × 10 −3
2.70 × 10 −3
2.70 × 10 −3
8.89 × 10 −3
7.8 × 10 −3
6.59 × 10 −3
C20 **
Jg −1°C −1
0.9
0.9
0.9
0.4
0.5
0.5
A c**
°C−1
4.5 × 10 −4
4.5 × 10 −4
4.5 × 10 −4
2.9 × 10 −4
1.0 × 10 −4
1.0 × 10 −4
*
Value taken from the appropriate Australian Standard, i.e. AS 1531, AS 1746, AS 1222.1, AS 1222.2.
**
Values are median values of data sourced from several references including: —
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.
—
Draft IEEE Standard, ‘Calculating the Current-Temperature relationship of Bare Overhead Conductors’, 1993.
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 210°C with a significant proportion of the annealing taking place during the cooling period following a fault. This annealing is cumulative over the life of the conductor. It anneals rapidly at temperatures exceeding 340°C and commences melting at approximately 645°C. The mechanical properties of the steel core of ACSR are affected very little at these temperatures. Zinc melts at approximately 420°C. Copper loses 10% of its tensile strength at a temperature of 220°C.
To provide for a loss of conductor tensile strength of less than 5% due to fault conditions over its life, the 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 (mm²)
Maximum temperature
HDCu
60
200°C
AAC, AAAC/1120, ACSR/GZ,
100
160°C
300 to 500
150°C
100
220°C
Conductor type
ACSR/AZ, ACSR/AC AAAC/6201A SC/GZ, SC/AC OPGW
400°C ***
***Dependent on construction. Reference: Roehmann, LF and Hazan, E ‘Short time annealing characteristics of electrical conductors’, AIEE Trans 82/3 p1061, Dec 1963.
Sag under fault Overhead lines have been known to sag into subsidiary lines or undercrossings under fault. If this is to be avoided it may be advisable for the line to be designed to have a positive clearance to the lower conductor. It is recommended that the appropriate non-flashover distance from AS 2067 for the system voltage be used for this clearance. Movement of conductors under fault The movement of conductors due to the electromagnetic forces generated by large short time current is a complex matter for which a simple satisfactory solution is not available. The Transmission Line Reference Book—115-138 kV Compact Line Design (EPRI EL-100-V3, Research Project 260, 1978) Section A3 ‘Simulation and Tests of Motion Due to Fault Currents’—gives equations which may be used to determine conductor swing and the mechanical forces due to fault currents.
By taking these criteria and the degree of reliability required into account, a suitable compromise on structure design, conductor configuration and economics can be achieved
