Transmission Line Uprating Guide 1000717
Transmission Line Uprating Guide TR-1000717 Technical Progress, November 2000
EPRI Project Manager M. Ostendorp
EPRI • 3412 Hillview Avenue, Palo Alto, California 94304 • PO Box 10412, Palo Alto, California 94303 • USA 800.313.3774 • 650.855.2121 •
[email protected] • www.epri.com
DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT EPRIsolutions Engineering and Test Center - Haslet
This is an EPRI Level 2 report. A Level 2 report is intended as an informal report of continuing research, a meeting, or a topical study. It is not a final EPRI technical report.
ORDERING INFORMATION Requests for copies of this report should be directed to the EPRI Distribution Center, 207 Coggins Drive, P.O. Box 23205, Pleasant Hill, CA 94523, (800) 313-3774. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. EPRI. POWERING PROGRESS is a service mark of the Electric Power Research Institute, Inc. Copyright © 2000 Electric Power Research Institute, Inc. All rights reserved.
CITATIONS This document was prepared by EPRIsolutions Engineering and Test Center - Haslet 100 Research Drive, P. O. Box 187 Haslet, Texas 76052 Principal Authors E. Fantaye M. Ostendorp Power Delivery Consultants, Inc. 1324 Regent Street Niskayuna, New York 12309 Principal Author D. Douglass This document describes research sponsored by EPRI. The publication is a corporate document that should be cited in the literature in the following manner: Transmission Line Uprating Guide, EPRI, Palo Alto, CA: 2000. 1000717.
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ABSTRACT The objective of the Transmission Line Uprating Guide is to document both common and uncommon methods for increasing the power transmission capacity of existing overhead transmission lines. Most of the methods included in this guide require less capital investment and shorter outages than the construction of new transmission lines or extensive reconstruction of existing lines. The emphasis of this uprating guide is on methods of increasing the thermal capacity of short high voltage (HV) lines without noticeably reducing service reliability. This guide on line uprating is limited to methods that do not require extensive structural modifications, reconstruction, or wholesale replacement of existing structures though certain approaches may require the structural reinforcement of angle and dead-end wire supports. Generally, this implies changes and modifications that will not increase the transverse or vertical loading applied to suspension structures by more than 20%. Though the solutions proposed may not suitable for all anticipated ice and wind loading levels, at least some of the methods proposed should be applicable regardless of the loading environment. The objectives of this uprating guide are to suggest methods and explain techniques that allow significantly increased power flow on existing distributed assets without extensive disruption to the operation of existing facilities. Regardless of the situation, in all cases, the issue of power line reliability and public safety is primary while economic issues are considered secondary. Based on this premise, the emphasis is on uprating techniques that yield the maximum increase in rated transmission line power flow given restrictions on outage time and minimum capital investment.
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CONTENTS 1 INTRODUCTION ..................................................................................1-1 Scope...................................................................................................................... 1-1 Objectives ............................................................................................................... 1-1 Background............................................................................................................. 1-1
2 POWER TRANSMISSION FLOW CAPACITY LIMITS .........................2-1 Surge Impedance Loading Limits............................................................................ 2-3 Voltage Drop Limits................................................................................................. 2-4 Thermal Limits ........................................................................................................ 2-5 Line Uprating and System Needs ........................................................................... 2-5
3 TRANSMISSION LINE UPRATING CONSTRAINTS ...........................3-1 The Sag-Tension Envelope .................................................................................... 3-1 Tension-Elongation Diagram (Normal) .............................................................. 3-4 Electrical Clearances .............................................................................................. 3-5 Applicable Code Clearances ............................................................................. 3-5 The Influence of Line Voltage on Clearance...................................................... 3-7 Reduced Clearance for EHV Lines with Limited Switching Surge Levels.......... 3-7 Power System Conditions When Clearances Apply .......................................... 3-8 Examples of Clearance Assurance Methods..................................................... 3-9 Installation Buffers on New Lines ...................................................................... 3-9 Upgrading Buffers............................................................................................ 3-10 Probabilistic Clearances .................................................................................. 3-11 Electrical Losses ................................................................................................... 3-11 Loss Calculations – Examples......................................................................... 3-12 Loss Calculations – Use of Load and Loss Factors......................................... 3-12 Environmental Effects ........................................................................................... 3-13 Structure & Foundation Loads .............................................................................. 3-15 Ice Loading ...................................................................................................... 3-18 Wind-Induced Fatigue & Flashover....................................................................... 3-20 Connectors & Conductor Hardware ...................................................................... 3-21
4 CALCULATION OF OVERHEAD LINE THERMAL RATINGS.............4-1 Rating Definitions.................................................................................................... 4-1 High Temperature Clearance to People, Buildings, & Lines.............................. 4-1 Annealing of Aluminum and Copper .................................................................. 4-1 How Weather Changes Affect Line Ratings ...................................................... 4-2 vii
Heat Balance Methods............................................................................................ 4-2 Definition of Variables for Heat Balance Calculations........................................ 4-3 Radiation ........................................................................................................... 4-4 Convection......................................................................................................... 4-5 Natural Convection........................................................................................ 4-5 Forced Convection ........................................................................................ 4-6 Solar Heating..................................................................................................... 4-9 Altitude of the Sun ......................................................................................... 4-9 Ohmic Losses.................................................................................................. 4-14 Thermal Rating – Dependence on Location and Orientation ................................ 4-14 Thermal Rating – Dependence on Conductor Parameters ................................... 4-15 Thermal Ratings – Dependence on Weather Conditions ...................................... 4-17 Thermal Ratings – Dependence on Maximum Allowable Conductor Temperature (MACT) ................................................................................................................. 4-18
5 CONSEQUENCES OF TRANSMISSION LINE OPERATION AT HIGH TEMPERATURE .....................................................................................5-1 Conductor Material Properties ................................................................................ 5-1 Conductor Design & Construction........................................................................... 5-1 Non-Standard Conductors................................................................................. 5-5 SDC – “Self-damping Conductor................................................................... 5-5 TW – “Trapezoidal Wire” ............................................................................... 5-6 T2 – “Twisted 2 Conductor ............................................................................ 5-6 ACSS – “Aluminum Conductor Steel Supported” .......................................... 5-6 Stress-Strain Characteristics .................................................................................. 5-7 Creep Elongation .................................................................................................... 5-9 Creep Due to Heavy Loading. ......................................................................... 5-10 Annealing of Aluminum ......................................................................................... 5-10 Residual Strength Predictor Equations for Aluminum Conductros................... 5-13 Thermal Elongation............................................................................................... 5-14 High Temperature Creep Elongation .................................................................... 5-16 Effect on Sag-Tension ..................................................................................... 5-16 Creep Predictor Equations .............................................................................. 5-17 Creep Predictor Equations for High Temperature Operations..................... 5-17 Connectors at High Temperature.......................................................................... 5-20 Connector Breakdown Process ....................................................................... 5-20 High Temperature Effects on Connector Joint Compound .............................. 5-21 New and Existing Connectors.......................................................................... 5-22 Mitigation of Connector High Temperature Operation ..................................... 5-22
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Conductor Hardware............................................................................................. 5-22 Metallic Conductor Hardware .......................................................................... 5-23 Non-Metallic Conductor Hardware................................................................... 5-24
6 UPRATING BY INCREASING THE MAXIMUM ALLOWABLE CONDUCTOR TEMPERATURE .............................................................6-1 Evaluating Sag Clearance Under Everyday Loading .............................................. 6-1 Predicting High Temperature Sag and Tension – Homogeneous Conductors........ 6-2 Predicting High Temperature Sag and Tension – Non-homogeneous Conductors. 6-4 Ignoring Aluminum Compression in ACSR........................................................ 6-4 Accounting for Aluminum Compression in ACSR .............................................. 6-8 Measurement of Sag-Tension at High Temperature........................................ 6-10 Conductor and Connector Inspection Techniques ................................................ 6-11 Re-Tensioning & Wind-Induced Conductor Motions ............................................. 6-11 Raising Attachment Points.................................................................................... 6-11
7 PROBABILISTIC METHODS OF LINE UPRATING.............................7-1 Probabilistic Clearances ......................................................................................... 7-2 Determining the Probability of Electrical Clearance Violations................................ 7-2 Probabilistic Loss of Strength ................................................................................. 7-3 Wind Speed Data Adjustments.......................................................................... 7-3 Load Current Assumptions and Annealing Calculation...................................... 7-5 Emergency and Normal Ratings........................................................................ 7-5 Limitations of the Probabilistic Approach........................................................... 7-6 Simplified Method of Probabilistic Annealing Calculation .................................. 7-7
8 DYNAMIC UPRATING METHODS.......................................................8-1 Where Dynamic Ratings Should Be Applied........................................................... 8-1 Uncertain Load Growth...................................................................................... 8-1 Maintain Reliability............................................................................................. 8-1 Open Access & Economic Transfers ................................................................. 8-2 Dynamic versus Static Uprating .............................................................................. 8-2 Dynamic Ratings are Normally Higher than Static Ratings................................ 8-3 Occasional Damage Avoided ............................................................................ 8-3 An Alternative to Less-Conservative Static Ratings........................................... 8-4 Real-time Monitoring Methods ................................................................................ 8-5 Indirect Clearance Determination with Conductor Temperature or Weather Monitors............................................................................................................. 8-5 Direct Clearance Determination with Sag-Tension Monitors ............................. 8-6 Field Test results..................................................................................................... 8-7
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Comparison of Weather Monitor and Tension Monitor-Based Dynamic Line Ratings .............................................................................................................. 8-9 Rating Variation in Adjacent Line Sections...................................................... 8-11
9 RECONDUCTORING WITHOUT STRUCTURE MODIFICATIONS......9-1 TW .......................................................................................................................... 9-1 ACSS ...................................................................................................................... 9-1 ACSS Conductor Designs ................................................................................. 9-1 Advantages & Disadvantages of ACSS............................................................. 9-1 Higher Maximum Temperature .......................................................................... 9-2 Thermal Elongation ........................................................................................... 9-3 Self-Damping..................................................................................................... 9-3 Low Creep Elongation ....................................................................................... 9-4 New Line Application of ACSS .......................................................................... 9-4 High Temperature Aluminum Alloy Conductors ...................................................... 9-6 High Temperature Alloys of Aluminum .............................................................. 9-7 Special Invar Steel Core.................................................................................... 9-7 Gapped Construction......................................................................................... 9-9 Comparing ACSS and High Temperature Alloy Conductors ........................... 9-10
10 UPRATING CASE STUDIES............................................................10-1 Case Study #1 – 69-kV, Copper Conductor, Short Spans, 50% Rating Increase . 10-1 Line Description............................................................................................... 10-1 Uprating Analysis............................................................................................. 10-2 Case Study #2 – 69-kV, ACSR Conductor, Short Spans, 30% Rating Increase... 10-2 Line Description............................................................................................... 10-2 Uprating Analysis............................................................................................. 10-3 Case Study #3 – 230-kV, 795kcmil ACSR, Medium Spans, Steel Lattice, 10% Rating Increase ................................................................................................................ 10-3 Line Description............................................................................................... 10-3 Uprating Analysis............................................................................................. 10-4
11 REFERENCES & PAPERS ..............................................................11-1 [A] Power Flow Limits for Overhead Lines ............................................................ 11-1 [B] Transmission Line Design ............................................................................... 11-1 [C] Thermal Rating of Lines .................................................................................. 11-1 [D] High Temperature Effects - Conductor............................................................ 11-2 [E High Temperature Effects - Connectors ........................................................... 11-3 [F] High Temperature Effects - Hardware ............................................................. 11-3 [G] Probabilistic Rating Methods........................................................................... 11-4
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[H] Dynamic Rating Methods ................................................................................ 11-4 [I] Reconductoring Lines with Novel Conductors .................................................. 11-5 [J] Sag-tension Calculations for Overhead Lines .................................................. 11-5
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FIGURE LIST Figure 2-1 Maximum Power Flow Considering System Stability.............................................. 2-2 Figure 2-2 Phasor Diagram for Stability & Voltage Illustration. ................................................ 2-4 Figure 3-1 Sag Diagram Showing Sags for Various Times and Loading Conditions................ 3-2 Figure 3-2 Diagram Showing Variation in Conductor Tension as a Function of Length and Loading Condition..................................................................................................... 3-5 Figure 3-3 Basic Electrical Ground Clearance Diagram for Bare Overhead Transmission Lines ............................................................................................................................... 3-6 Figure 3-4 Median Survey Results as to Why People Oppose Transmission Lines................3-14 Figure 3-5 NESC Transmission Line Loading Areas ..............................................................3-17 Figure 3-6 NESC Wind Pressure Values for Transmission Line Design. ................................3-17 Figure 4-1 Transmission Line Conductor Emissivity as a Function of Time. ...........................4-16 Figure 5-1 Stress-Strain Curve for ACSR Conductor............................................................... 5-8 Figure 5-2 Stress-Strain Curve for All Aluminum Conductor.................................................... 5-9 Figure 5-3 Annealing of 0.081 Inch Diameter Hard Drawn Copper Wire.................................5-11 Figure 5-4 Annealing of 1350-H19 Hard Drawn Aluminum Wire.............................................5-12 Figure 6-1 Change in Sag for All Aluminum Conductor as a Function of Span Length ............ 6-3 Figure 6-2 Sag for a "Strong" ACSR Conductor as a Function of Conductor Temperature and Ruling Span Length .................................................................................................. 6-7 Figure 6-3 Comparison of Sag Change with Temperature for All Aluminum Conductor, 45/7 (Type 7) ACSR, and 30/19 (Type 23) ACSR............................................................ 6-8 Figure 6-4 Sag at High Temperature Calculated with and without Aluminum Compression ................................................................................................................... 6-9 Figure 6-5 Final Sags for Mallard ACSR in a 1200 ft Span.....................................................6-10 Figure 6-6 Measured Line Tension as a Function of Line Current for a Line with 30/19 Mallard ACSR ................................................................................................................6-11 Figure 7-1 Wind Speed Distribution at 70°F Showing Actual Reported Values (Shown in Parentheses) and the Author’s Smoothed Distribution Curve. ......................................... 7-4 Figure 7-2 Typical Annealing of Aluminum Wires (Alcoa)........................................................ 7-5 Figure 8-1 - Probability Density Distributions for a Typical Circuit Load and Dynamic Rating.............................................................................................................................. 8-3 Figure 8-2 Wind Speed (15 min average) at Two Locations 1.5 km Apart Along a 230-kV Line in the Eastern US..................................................................................................... 8-8 Figure 8-3 Comparison of Weather-Based and Tension-Based Cumulative Rating Distributions ...................................................................................................................8-10 Figure 8-4 Comparison of Tension-Based Rating Estimates for 4 separate Line Sections .....8-10 Figure 9-1 Illustration of Typical Behavior of ACSS Conductor Illustrating that Initial and Final Sags are Nearly Identical........................................................................................ 9-4 Figure 9-2 Application of ACSS in New Line Design Showing 30% Higher Thermal Rating with the Same Maximum Sag and Tension Loading on Structures ....................... 9-5
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Figure 9-3 Ampacity and Sag of Original Drake ACSR and Calumet ACSS/TW Replacement Conductor as a Function of Maximum Allowable Temperature .................. 9-6 Figure 9-4 Plots of Conductivity and Loss of Strength for High Temperature Japanese Aluminum Alloys.............................................................................................................. 9-8 Figure 9-5 Comparison of ACSR-type Conductors with Invar and Conventional Steel Cores. ............................................................................................................................. 9-9 Figure 9-6 Summary Table Showing Gapped and Conventional Constructions for Japanese High Temperature Conductors. ....................................................................... 9-9 Figure 10-1 5 year Total Cost vs. Percent Increase in Rating for Case Study #3 ...................10-4
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TABLE LIST 2-1 Power Flow Limits on Lines and Cables............................................................................ 2-3 3-1 Minimum Vertical Ground Clearances According to NESC C2-1997, Rule 232C .............. 3-7 3-2 Minimum Vertical Ground Clearances According to NESC C2-1997, Rule 232D .............. 3-8 3-3 The Impact of Distance on Public Opposition to Power Transmission Lines.....................3-15 3-4 Definition of NESC Loading Areas ...................................................................................3-16 3-5 Ratio of Iced to Bare Conductor Weight ...........................................................................3-19 3-6 Cyclic, Wind-induced Conductor Motions.........................................................................3-22 4-1 Variation in Conductor Temperature and Rating with Weather Conditions (IEEE738)....... 4-2 4-2 Definitions of Thermal Rating Equation Variables ............................................................. 4-3 4-3 Solar Azimuth Constant, C, as a Function of “Hour Angle,”,ω, and Solar Azimuth Variable,χ. ......................................................................................................................4-11 4-4 Altitude, Hc, and Azimuth, Zc, in Degrees of the Sun at Various Latitudes for an Annual Peak Solar Heat Input ........................................................................................4-11 4-5 Total Heat Flux Received by a Surface at Sea Level Normal to the Sun’s Rays ..............4-12 4-6 Elevation Correction Factor..............................................................................................4-13 4-7 Solar Heat Multiplying Factors, Ksolar for High Altitudes .................................................4-14 4-8 Thermal Rating for 795kcmil, 26/7 ACSR (Drake) at 100 °C with 40 °C Air Temperature, Emissivity=Absorptivity=0.5, 2ft/sec (0.61m/sec) Crosswind, and Direct Sun at 2PM on June10.........................................................................................4-15 4-9 Illustration of the Effect of Diameter, Resistance, Emissivity & Absorptivity on Thermal Rating...............................................................................................................4-17 4-10 Effect of Weather Conditions on Thermal Ratings. In all Cases, the Conductor is 795kcmil, 26/7 ACSR (Drake), Emissivity=Absorptivity=0.5, Direct Sun on June10, Clear Air,at Sea Level,Latitute=40deg, with Conductor at 100 °C ...................................4-18 4-11 Line Thermal Rating as a Function of Maximum Allowable Conductor Temperature. In all Cases, the Conductor is 26/7 795kcmil ACSR (Drake) with Emissivity=Absorptivity=0.5, Direct Sun on June 10, Clear Air, at Sea Level, Latitude=40deg, with Line Oriented East-West...............................................................4-19 5-1a Basic Material Properties of Wire Used in Overhead Conductor ..................................... 5-2 5-1b Basic Material Properties of Wire Used in Overhead Conductor ..................................... 5-3 5-2 Comparison of Mechanical Properties for Different Strandings of 795 kcmil ACSR conductors (US Common Units) ...................................................................................... 5-4 5-3 Comparison of Mechanical Properties for Different Strandings of 400mm2 ACSR Conductors (SI Units) ...................................................................................................... 5-4 5-4 Comparison of AAC with AAC/TW Alternatives................................................................. 5-6 5-5 Formula Constants (Metric Units).....................................................................................5-17 5-6 Formula Constants (English Units)...................................................................................5-18 6-1 Sag-tension Calculations for 37 AAC (Arbutus)................................................................. 6-2 6-2 Coefficients of Thermal Expansion.................................................................................... 6-4
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6-3 Sag-Tension Calculations for 37 AAC (Arbutus) ............................................................... 6-5 6-4 Sag-Tension Calculations for 37 AAC (Arbutus) ............................................................... 6-6 7-1 Assumed Hours of Combined Wind and Air Temperature in 30 Years for a Typical Protected Transmission Line Right-of-Way...................................................................... 7-4 7-2 Conductor Ratings Based on 12% to 15% Loss of Aluminum Wire Strength Over 30 Years Where the Normal Load does not Occur for More than 13,000 Hours and the Contingency Load does not Occur for More than 600 Hours. The Loads are Assumed to be Random .................................................................................................. 7-6 8-1 Effect of Assumed Wind Speed on Thermal Rating for Drake 795 kcmil ACSR at 100°C, Assuming Full Sun and an Air Temperature of 40°C............................................ 8-4 9-1 ACSS Equivalents to Standard Type 16, 795 kcmil, 26/7 ACSR (Drake) .......................... 9-2 9-2 Continuous Ampacity of Equivalent ACSR and ACSS Conductors as a Function of Maximum Allowable Conductor Temperature .................................................................. 9-3 9-3 Illustration of the Lower Thermal Elongation of ACSS Conductor...................................... 9-3 9-4 Maximum Operating Temperatures for High Temperature Alloys Made in Japan.............. 9-7 9-5 Conductivity of High Temperature Alloys Made in Japan .................................................. 9-7
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1 INTRODUCTION The objective of the Transmission Line Uprating Guide is to document and explain both common and uncommon methods for increasing the power transmission capacity of existing overhead transmission lines. Most of the methods included in this guide require less capital investment and shorter outages than the construction of new transmission lines or extensive reconstruction of existing lines. The emphasis of this uprating guide is on methods of increasing the thermal capacity of short high voltage (HV) lines without noticeably reducing their service reliability.
Scope This guide on line uprating is limited to methods that do not require extensive structural modifications, reconstruction, or wholesale replacement of existing structures though certain approaches may require the structural reinforcement of angle and dead-end wire supports. Generally, this implies changes and modifications that will not increase the transverse or vertical loading applied to suspension structures by more than 20%. Though the solutions proposed may not suitable for all anticipated ice and wind loading levels, at least some of the methods proposed should be applicable regardless of the loading environment.
Objectives The objectives of this uprating guide are to suggest methods and explain techniques that allow significantly increased power flow on existing distributed assets without extensive disruption to the operation of existing facilities. Regardless of the situation, in all cases, the issue of power line reliability and public safety is primary while economic issues are considered secondary. Based on this premise, the emphasis is on uprating techniques that yield the maximum increase in rated transmission line power flow given restrictions on outage time and minimum capital investment.
Background Over the years, the Electric Power Research Institute (EPRI) has supported considerable research in the areas of transmission line uprating and upgrading in a variety of forms. In particular, this guide draws upon the results of these EPRI projects to evaluate new line uprating technologies and research into the high temperature operation of stranded conductors and connectors. Previous investigations have explored the accuracy of sag and tension analysis models and the effect of high temperature operation on the expected service life of suspension and termination hardware. Results of these investigations have been reported in various EPRI technical reports produced over the last 8 years and can be obtained from the EPRI distribution center in Palo Alto, CA.
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2 POWER TRANSMISSION FLOW CAPACITY LIMITS The need for additional power transmission transfer capacity has traditionally been met by the construction of new high voltage lines and substations. However, with continuously increasing blocks of power being moved from an increasing number and size of generating stations over increasing distances, novel transmission line designs for increasing line operating voltages were and still are explored by the industry. As the length of high voltage power lines constructed in the United States continuously grew, public opposition to this construction activity has increased to the point where, in some areas of the United States and other developed countries, it is more and more difficult or nearly impossible to obtain permission to build new facilities. Also, issues such as the environmental land use, esthetics, and electrical and magnetic field environmental effects have arisen to hinder and delay the planning and construction of new transmission lines. While environmental and health issues have been sometimes raised out of genuine concern of the public, many times opposition has focused on these issues because a selected number of people does not appreciate the appearance of overhead lines within their neighborhoods and communities. While public opposition to the construction of new transmission lines has mounted a strong campaign, the traditional power delivery system planning techniques, appropriate to a regulated industry experiencing an extended period of sustained load growth, are increasingly being questioned. Most of the questions raised by the opposition in such instances center on one of two issues. First, the slowing of load growth on the overall power delivery system from a rate ranging from 5% to 10% to a rate of 1% to 5%. Second, the inability to plan the transmission grid and delivery system given the situation that the location and generating capacity of new generating stations and large capacity users is unknown. Consequently, transmission planning horizons have shortened from as much as 20 years to as little as 2 to 3 years, and the focus has shifted to incremental uprating techniques. These short lead-time and economic incremental uprating techniques typically yield transfer capacity increases of less than 10%. With the addition of new Independent Power Producers and Co-generators to many transmission systems, the combined effect of volatile price differentials, increased regulatory support and requirements to provide open access, and the uncertainty associated with the future locations of generators, lead to much greater uncertainty in the prediction of future loads. At the same time, in several instances in New York State, line-rebuilding projects deferred to allow the installation and evaluation of conductor temperature monitors were never implemented because the projected load growth was accommodated by the installation of impedance control devices on neighboring delivery systems. Such utility experiences indicate the need for flexibility whenever dealing with modifications of transmission lines. Therefore, it is important for the operator to explore transmission line modification alternatives that are capable of being implemented quickly and economically.
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This application guide emphasizes techniques for uprating existing transmission lines with minimum capital investment. Although power flow through components of the transmission system are the result of thermal, voltage drop, or phase shift limitations, this application guide deals primarily with analysis and design methods to increase the thermal capacity of existing high voltage overhead lines. More specifically, the application guide focuses on methods and tools available for increasing the power transfer capacity of ‘short’ transmission lines since these facilities are mostly affected by thermal limitations.
Figure 2-1 Maximum Power Flow Considering System Stability.
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Surge Impedance Loading Limits As power flows along high voltage transmission lines, there is an electrical phase shift that increases proportionally with the distance of the line and the magnitude of the power flow. As this phase shift increases, the system in which the line operates grows increasingly unstable when subjected to electrical disturbances. Typically, for very long transmission lines, thermal operational limits are not applicable and the power flow must be limited to what is commonly called the Surge Impedance Loading (SIL) of the line. Surge Impedance Loading is defined as the product of the termination bus voltages divided by the characteristic impedance of the line. Since the characteristic impedance of various HV and EHV lines is not dissimilar, the SIL can commonly be approximated by the square of the system voltage. Typically, such stability related operational limits are likely to govern the maximum allowable power flow on lines that are more than 150 miles (240 km) in length. Typical stability limits as a function of transmission line system voltage are listed in Table 2-1. For very long transmission lines of more than 500 miles (800 km), the power flow limitation may be less than the SIL as shown in Table 2-1. It should be noted that stability limits on power flow of high voltage lines may be as low as 20% of the power flow limits stipulated by thermal operational requirements of the transmission line. Table 2-1 Power Flow Limits on Lines and Cables
System kV
XL (•/mi)
XC (•/km)
(M•-mi)
(M•-km)
Surge Impedance
SIL
Thermal Rating
(•)
(MW)
(MW)
Transmission Overhead Line Characteristics 230
0.75
0.47
0.18
0.29
367
145
440
345
0.60
0.37
0.15
0.24
300
400
1500
500
0.58
0.36
0.14
0.26
285
880
3000
765
0.56
0.35
0.14
0.26
280
2090
8000
3050
2100
Transmission Cable Characteristics 345
0.25
0.16
0.0060
0.0097
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The surge impedance and load limit for a transmission line can frequently be increased by the addition of a series of capacitors or other impedance changing devices. However, little can be done to increase the surge impedance load limit of an existing transmission line other than the bundling of those transmission lines (addition of a second conductor) that were initially constructed with a single conductor per phase.
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Figure 2-2 Phasor Diagram for Stability & Voltage Illustration
Voltage Drop Limits In addition to the electrical phase shift, voltage magnitude decreases with distance. Generally, for transmission lines, this drop in voltage is limited to between 5% and 10% of the sending termination bus voltage. The power flow (in MVA or MW) that corresponds to the maximum allowable decrease in voltage magnitude during the operation is defined as the voltage drop limit of the high voltage line. As in the case of the phase shift, a transmission line’s voltage drop limit decreases proportionally to the transmission distance (length of transmission) and is generally higher than the high voltage line’s thermal limit for short lines but less than the line’s stability limit for very long lines. The voltage drop on the system normally limits the power flow on HV or EHV transmission lines that are between 50 and 150 miles (approximately 80 to 240 km) in length. Voltage drop limits in regards to the power flow can be as low as 40% of the thermal limit of a high voltage transmission line.
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Voltage drop limits are primarily a function of the transmission line series impedance. In most cases, resistance plays a minor role in the constraints imposed on transmission lines. Therefore, as is the case for SIL limits, there is very little that can be done to change the voltage drop of an existing line other than to change line conductors. For example, reconductoring of an existing 230-kV line by replacing original 636 kcmil ACSR Hawk conductor with a 954 kcmil ACSR Rail conductor only increases the voltage drop limit by 5%. Adding shunt capacitors at the end of the transmission line may increase voltage drop limits. The advantage in adding shunt resistors to a voltage drop constrained line is usually much less expensive than the reconstruction of the line.
Thermal Limits Thermal power flow limits on high voltage overhead lines are intended to limit the temperature attained by the energized conductors and the resulting sag and loss of tensile strength of the component. In most cases, the maximum conductor temperature permitted in the operation of modern high voltage transmission lines is restricted as a function of ground clearance concerns rather than by the annealing of the aluminum strands. Thermal limits, as typically calculated, are not a function of the transmission line length. Thus for a given line design, the thermal limit of a 1 mile (1.6 km) long transmission line and the thermal limit of a 300 mile (500 km) long line are identical. Essentially, thermal limits usually determine the maximum power flow capacity of lines that are less than 50 miles (80 km) in length. Several methods can be used by utilities to increase the MVA capacity of their transmission lines. Some of these methods are based on technically straightforward tasks, such as reinforcing the support structures and load carrying components of the system or the restringing of the line with a larger conductor or a bundle of conductors. However, these alternatives come at a price and mostly require a sustained outage on the existing system. In addition to the refurbishment cost involved, there construction will have to be managed and mitigated within the right-of-way requiring environmental permits and restoration of the right-of-way condition. Alternatively, if an outage is to be avoided or the duration to be minimized, special construction methods are required to allow service while the work is in progress. Other thermal uprating methods, such as methods employing dynamic thermal ratings or voltage uprating, may require little or no line outage time and require less capital investment and lead time than the reconductoring or reinforcing of the structures. The disadvantage of these methods are that there is a greater degree of technical sophistication required in using these methods in such a manner that ensures the safe and reliable operation of the system at higher loading levels.
Line Uprating and System Needs The selection of an appropriate uprating method for a particular transmission line requires close coordination between utility operators, planners, and designers, and a thorough understanding of the mechanical, electrical and environmental aspects of the line uprating. Selecting the most
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appropriate method of uprating yields a transmission line of increased MVA capacity that is economically sound and consistent with present and future transmission system needs. System concerns and issues relate to a number of short and long-term system planning questions, ranging from how to survive the next winter (summer) peak to providing transmission capacity from a major proposed generation addition to the delivery grid. Sometimes these system effects are complicated, difficult to analyze, and typically involve several utilities. For example, several electric utilities may enter into a wheeling arrangement, which results in increased flows on lines owned by still other utilities. Sometimes, major changes in power flow patterns occur as a result of new construction such as the installation of a generating station, which may reverse the direction of the previously observed flow of power. Short and long-range load flow, fault, and system stability studies are required to thoroughly assess the impact of such individual changes on the delivery system and to predict future transmission needs. Once the need for additional transmission capacity has been identified, the first question that needs to be answered is whether to construct new facilities or to attempt to gain the additional capacity from existing installations. A number of factors need to be considered when making this decision. As a first step, the utility is required to decide if the cause of the present limitation is mandated by maximum power flow, voltage control, stability, or reliability of service? Other questions to be answered address the issue if there is a need for base load or peaking (or perhaps emergencies), is the load seasonal, is the effect localized or does the limitation affect a large area of the delivery system? In many cases, increased maximum power flow capability can be accomplished either by raising the voltage or the current of a transmission line. If the problem involves stability, a reduction of the effective impedance of the transmission line can be achieved with increased voltage which will reduce the per unit impedance. If the need is to cover short-term loading contingencies, the problem is more likely to require experience and knowledge of conductor temperatures, real time monitoring, and dynamic rating to achieve an acceptable solution. Other relevant questions that need to be addressed relate to system requirements of specific lines. For example, can the existing transmission lines be taken out of service long enough to allow for some form of reconstruction? If not, is it possible to use construction techniques and temporary structures to maintain reliable service during the reconstruction of the transmission line? On the other hand, can the required modifications be (and this takes us over into the physical aspects of uprating) performed using live line work methods and tools? Frequently, the uprating of a line by increasing the voltage may only require changing of insulators, which can often be done live. Alternatively, the installation of sag monitoring devices for dynamic ratings can be performed using a hot stick and need not result in line outages. Frequently the selection of the most appropriate alternative is directly influenced by the schedule set forth by the grid operator in which to achieve the system modification. Immediate needs by system operators may be able to be met by the application of current uprating methods where the economic impact of the cost of losses is of secondary importance. These uprating methods of course could not be deployed in those cases that are dictated by longer-term operational needs and economics. Optimal transmission line economics requires consideration of the cost of construction as well as the present worth of the cost of losses and maintenance. One alternative may result in greater 2-6
capital cost immediately while another may give higher cost of losses over a period of years. Consequently, to fully evaluate each alternative, a detailed analysis is required to properly estimate changes in energy costs, interest rates, and other financial characteristics to determine the sensitivity of the highest ranked solution to changes in economic parameters. Adding to the complexity of such an analysis is the fact that these economic parameters are continuously changing in difficult to predict ways. Sometimes financial characteristics rather than economic factors dominate the decision process and the final outcome. For example, a refurbishment project may be economically advantageous but it may be considered impossible for financial reasons. An example of such a situation is the often repeated claim that it would be economically justified to change all of an electric utility’s distribution transformers to minimize losses and realize additional revenues. While an economic and technically justified case could be made to justify such a modification, the financial aspects relating to such a large expenditure render it impossible. To further complicate the evaluation of such analyses, it should be noted that the time frame associated with the achievement of the primary goal, the increased power transfer, adds another important constraint to the problem of ranking various alternatives. While an increase in the current rating of a transmission line can be used to cover an immediate or short-term need within the delivery system, such an approach is not appropriate to effect a long term increase in the transfer capacity of the system. Another consideration to be evaluated is related to the desire to implement system wide changes to facilitate increased power transfers rather than the uprating of individual transmission lines. One aspect of this with respect to transmission line uprating relates to the planned system wide implementation of changes rather than the modification of an individual line. Some utilities have considered the approach of uprating entire voltage classes of transmission line for the numerous benefits this has on overall system operation and maintenance, as well as providing additional transfer capacity to accommodate future load growth. A very basic question of the decision process is whether construction of new transmission lines is feasible. This decision involves physical considerations such as the availability of right-ofway and institutional considerations such as the difficulty in obtaining necessary authorizations. Frequently, physical and institutional considerations may overlap. In a similar manner, physical and institutional considerations have a strong effect on the uprating potential of transmission lines. If there is a physical constraint on the availability of right of way for the construction of a new line, there usually is also a physical constraint for uprating as it relates to the condition of existing transmission line structures and foundations. Essentially, are the support structures capable of bearing the additional weight imposed by reconductoring? Also, in most instances, there are physical constraints relating to the maximum conductor size that can be supported and the insulation strength prevalent on the transmission line. Similarly, increasing the line voltage may be limited by the conductor surface electric field and resulting corona while the support structure’s opening may limit switching surge over-voltages and dictate pre-insertion resistors in the circuit breakers. Other fundamental questions involving physical constraints include deciding if the existing transmission line has the potential to carry the desired capacity, if clearances are sufficient to increase the line voltage, or if the clearances are sufficient to add a larger conductor at a lower 2-7
tension. For example, old lines may have generous clearances that would make voltage uprating practical. On the other hand, old lines have often been constructed with such small conductor that corona effects would limit any increase in the line voltage. Also, the question is posed if the support structures are sufficiently robust and of a condition to allow reconductoring or permit the addition of a second conductor per phase? Finally the question arises if there are line facilities of a type that lend themselves to increase the transmission capacity via the dynamic rating of the conductor? Alternatively, it should be determined if present conductor current limits are defined unrealistically low given the present state of knowledge and technology? Sometimes new equipment and procedures can be utilized to remove previously existing physical restrictions on the power transfer capacity of a transmission line. Depending on the situation, synthetic insulators may provide superior contamination performance and result in a lesser structural load than porcelain suspension strings and can be used to withstand greater voltage stress in the same space. Also, new conductor manufacturing techniques and the deployment of such novel conductors that are particularly suited for the uprating of transmission lines provide additional options to electric utilities. At the same time, an easily overlooked physical constraint in the uprating of a transmission line is the proportion of angle and deadend structures to tangent structures on the particular line being considered for uprating. Angle and deadend structures frequently are required to be strengthened and/or rebuilt in the reconductoring of a transmission line whereas minimal changes may be required on tangent support structures. Therefore, the relative number of angle and deadend structures in the transmission line, which require replacement, directly affect both physical and economic feasibility of a selected uprating alternative. Other types of constraints may also affect the ranking of uprating alternatives in the evaluation of a particular transmission line. Frequently, institutional constraints brought forth by regulators and agencies may require addressing pressures brought to bear by licensing considerations. For example, is it less complicated and time consuming to gain permission to change some or all of the presently existing facilities than to build new ones? Often, institutional constraints may force the selection of a less economic alternative in order to meet schedules imposed by load growth characteristics or competitive pressures. Once the decision is made to seek additional transfer capacity by uprating existing lines, the process requires the evaluation of yet another group of alternatives that center on the choice of method and technologies used to increase the power transfer. For example, can the transmission line capacity be increased by raising the line voltage only? Alternatively, can the power transfer capacity be increased by raising the line current, or will it require an increase in the current and voltage? Finally, a decision is required on the use of methods and technologies to be deployed to achieve the objectives. Advantages and disadvantages of many of these approaches are addressed in subsequent sections of this application guide.
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3 TRANSMISSION LINE UPRATING CONSTRAINTS There are many factors that constrain the construction of overhead transmission lines. Examples of the primary issues affecting the construction of power lines include minimum operational and live working related electrical clearances, maximum structure wire and environmental loads and tensions, interruption of service, limits on capital expenditures, access restrictions, construction limitations, inspection and maintenance requirements, and environmental effects. Environmental effects include radio noise, audible noise, magnetic and electric fields, and induced voltage and current in nearby objects. In this section of the application guide, several of these constraints are considered and their consequences and impact are discussed in attempting to increase the power flow on existing transmission lines.
The Sag-Tension Envelope In the design, uprating, or simple maintenance of power transmission lines, the primary concern of importance is to ensure public safety while providing reliable power. Based on this premise, it is more important to operate a transmission line safely than to carry more power. To maintain the safe operation of a transmission line it is necessary to design the wires, support structures and related components such that they are capable of ensuring the safe operation of the transmission line under even the most severe weather conditions. Additionally, the safety of a transmission line is governed by the position of its energized conductors relative to the position of people, animals, vegetation, buildings, and vehicles that are nearby. Maintaining minimum distances to nearby people and objects is primarily a matter of limiting the sag of the energized conductors when subjected to high loads and associated high conductor temperatures regardless of the prevalent environmental and climatic conditions. In addition to making transmission lines safe, other important issues to consider in the analysis include the presence and magnitude of electric and magnetic fields (e.g. electric fields increase as the conductor gets closer to the ground), the maximum structure loads and tensions encountered during occasional periods of high wind and icing, and the maximum current that the transmission line is allowed to carry (i.e. its thermal rating). The maximum allowable power (current) flow of an existing transmission line is usually (though not always) determined by the conductor sag at high temperatures. Thus, the uprating of such transmission lines without reconductoring the facilities normally requires that an alternative is identified that permits the increased power flow while maintaining electrical clearances at the highest expected conductor temperature. Figure 3-1 is a basic sag-clearance diagram of a ruling span that illustrates how minimum ground clearance must be maintained under both heavy loading (ice and wind) and the high temperature operation at the rated capacity of the transmission line. Such loading events are anticipated to occur over the estimated service life of both new and re-rated transmission lines. The ruling span’s sag-clearance diagram shows expected ground clearance and line sags under normal, high ice and wind loads, and operation at the rated maximum temperature condition. It should be noted that the sum of the minimum ground clearance, the safety buffer, and the sag at the
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maximum operating temperature directly equates to the minimum attachment height which in turn equates to the minimum required support structure height and spacing. In a detailed analysis and design of a transmission line having many different spans, sag-clearance calculations must be developed and evaluated for all spans of each tension section.
Span Length
Init
Final - STC Final - LTC Max Load
TCmax
Buffer Normal Ruling Span Sag Variation Diagram
Electrical Clearance
GROUND LEVEL Figure 3-1 Sag Diagram Showing Sags for Various Times and Loading Conditions
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Definitions of the labels used in Figure 3-1 are provided as follows: “Init” constitutes the initial installed unloaded (with no ice or wind) sag of the conductor. The initial installed unloaded condition is typically determined at a conductor temperature of 10°C to 25°C (50°F to 80°F). This is also typically referred to as the line “ruling span stringing sag”. “Final – STC” constitutes the final sag of the conductor after a significant ice and wind loading event has occurred for a short time - typically an hour. STC stands for “Short Term Creep”. “Final – LTC” constitutes the final sag of the conductor expected after an extended period of service – typically 10 years – in which the conductor is assumed to maintain an even conductor temperature of 15°C (59°F) with no ice or wind loading. “LTC” stands for “Long Term Creep” which occurs even if heavy ice and wind loads never occur. “Max Load” constitutes the sag of the conductor during the specified maximum ice and wind loading at a reduced temperature – typically –18°C to 0°C (0°F to 32°F). It should be noted that the sag prior to the occurrence of this event is normally assumed to be the “Init” sag and that the sag observed upon conclusion of this event is considered the “Final STC” sag. “TCmax” constitutes the sag of the conductor when the conductor’s temperature reaches the maximum value for which the line has been designed – typically 50°C to 150°C. The conductor sag expected prior to the occurrence of this high temperature event is assumed to be the larger of the “Final STC” and the “Final LTC” sag. Further review of Figure 3-1 also shows the typical behavior of transmission line conductors where the expected conductor sag under maximum ice and wind loading conditions is less than the expected sag of the conductor at the maximum temperature condition. As stated previously, for small or weak conductors subjected to heavy ice loading, this may not be true. Note that Figure 3-1 illustrates the “snapshot” nature of traditionally used conductor sag-tension calculations. The actual conductor sag position at any time in the life of the transmission line depends on the actual mechanical and electrical load history of the line. For example, if the high loading event (ice and wind) is more severe or persists for a longer time than assumed in the determination of the Max Load condition, then the corresponding conductor sag at the Max Load and the associated increase in the sag will be greater than indicated in the figure. To account for these uncertainties, the use of safety buffers is required. The conductor sag never stops increasing with both time and high loading events throughout the life of the transmission line. As a result, the sag at a given conductor temperature (e.g. 15.5°°C, or 60oF) increases steadily over the years following construction. However, when subjected to moderate unloaded and loaded conductor tensions (typically 15% and 50% of rated strength), the rate of change in the conductor sag with each such event decreases over the life of the line. Thus, if a heavy ice loading event occurs 10 years after the initial installation, the permanent increase in the sag of the conductor is much smaller than if the loading event occurred within the first 6 months after construction of the transmission line. Similarly, under everyday unloaded conditions, the rate of change in the conductor sag will decrease with time.
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Tension-Elongation Diagram (Normal) The “tension-elongation” diagram shown in Figure 3-2 shows how the tension of the conductor changes in response to the changes in the sag as a function of the load, time, and temperature as shown in the preceding sag diagram (Figure 3-1). The initial unloaded (Init) sag corresponds to the initial unloaded (Init) tension. Increasing this initial tension decreases all of the transmission line sags but also results in an increase in the tension loads on angle and dead-end structures while decreasing the mechanical self-damping of the conductor. A significant reduction in the self-damping performance can lead to an increased likelihood of aeolian vibration-induced fatigue damage.
Conductor Tension
Conductor Tensile Failure
Normal Conductor Tension-Elongation Diagram Max Structure Tension Loads
Max
Init
Initial Aeolian Vibration Long term Aeolian Vibration TCmax
Elastic Modulus
Maximum Sag
Elongation Failure
Final
Conductor Length
Figure 3-2 Diagram Showing Variation in Conductor Tension as a Function of Length and Loading Condition
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With an older existing line that has reached its final sag, increasing the conductor tension reinitiates creep (though at a reduced rate) and yields the same increased angle and dead-end structure loads. At the same time, re-tensioning reduces the conductor’s mechanical selfdamping resulting in increased aeolian vibration amplitudes. When re-tensioning new and existing lines, the maximum conductor tension is the result of a combination of low conductor temperature and high wind and/or ice loading. With new lines, these increased tensions are a major determinant of angle and deadend structure cost. Similarly, with existing transmission lines, any increase in the maximum tensions is likely to lead to the need for reinforcement or replacement of angle and dead-end structures. Consequently, the maximum tensions resulting from the reconductoring of an older transmission line are a critical factor in deciding on the most suitable uprating alternative. Figure 3-2 shows the typical behavior of a transmission conductor where the tension difference between unloaded and loaded states may result in a tension increase of more than two times its original value. The specification of a realistic conductor modulus of elasticity (in regards to the stress-strain behavior) under high tension loads is important to calculating the maximum tension. The modulus of elasticity (actually the spring constant, EA) of the conductor therefore directly affects the resultant increase in tension between unloaded and loaded states. As the temperature of the conductor increases, its length and the resulting sag increases while the line tension decreases. Errors in modeling the conductor modulus of elasticity at significantly increased operating temperatures have little or no effect on the calculated sag but the related thermal elongation characteristics of conductors at high temperatures are very important. As is discussed later in the guide, due to the combination of steel and aluminum strands, the thermal elongation of ACSR can be particularly complex.
Electrical Clearances Minimum electrical clearances of the conductor must be maintained under all line loading and environmental conditions. Since the actual sag clearance of conductors on transmission lines is seldom monitored, sufficient allowance for this clearance (safety buffer) must be included in the process of the initial design or in the re-rating of existing transmission lines. Applicable Code Clearances In all cases, national codes may apply. In the United States, the National Electric Safety Code (NESC) is applicable. State codes may also apply. Minimum horizontal and vertical distances from energized conductor (“electrical clearances”) to ground, other conductors, vehicles, and objects such as buildings, are defined based on three parameters. Clearances are defined based on the transmission line to ground voltage, the use of ground fault relaying, and the type of object or vehicle expected within proximity of the line. The NESC Rules cover both vertical and horizontal clearances to the energized conductors. That is, the NESC safety code sets minimum spacing for energized conductors both above and next to people, vehicles, and buildings. This report considers only vertical clearances since our focus is on high temperature operation of transmission lines not on the width of the transmission line’s right of way. Horizontal clearances are typically specified and calculated for the high wind
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loading condition where the transmission line conductor catenaries are horizontally displaced by the wind. In such cases, the conductor temperature is low due to high convection cooling. Ground clearance minimums listed in the NESC safety code are primarily developed with respect to the height of the object or person anticipated to pass beneath the span. For example, a person with an overhead umbrella extended overhead at arms length may physically reach 10 ft (3 m) above ground, whereas a railroad car may reach as high as 20 ft (6 m) above the ground. Therefore the NESC safety code calls for a minimum ground clearance of 27 ft (8.2 m) for a low voltage conductor extending across a railroad and only 16.5ft (5 m) over “spaces, areas, or ways” accessible only to pedestrians. The difference in the mandated minimum ground clearance is due primarily to the height of the object under the transmission line. In each case, the vertical line clearance between the low voltage conductor and the top of the anticipated conflicting object is approximately the same. The following clearance diagram as shown in Figure 3-3 provides a breakdown of the minimum vertical clearance required between any “conflicting activity” and the energized conductor of a transmission line. The breakdown has been developed based on the references (Section I of the References) and does not allow for the precise calculation of electrical clearances in all the special cases covered by the NESC safety code. However, the breakdown does illustrate the basic approach taken by codes in determining minimum ground clearances for energized power line conductors.
Conductor at 115kV Transmission adder 0.4" per kV Conductor at 751 v to 22 kV 2 ft - Basic adder for distribution voltag Conductor at 0 to 750 v 1 ft electrical safety margin 1 ft mechanical safety margin "Conflicting Activity" be it person, truck, etc.
Figure 3-3 Basic Electrical Ground Clearance Diagram for Bare Overhead Transmission Lines
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Essentially, the minimum vertical ground clearance for any “supply” conductor (0 to 750 Volts) is specified by the NESC safety code as 16.5 ft (5 m) for power lines extending across objects such as roads, streets, driveways, parking lots, and farmland or any other type of land which can be traversed by vehicles. Similarly, based on the information shown in Figure 3-3, one may infer that this assumes a height of 14.5 ft (4.4 m) above any “conflicting activity”. It should be noted that energized line conductors passing over lakes and waterways must generally meet greater clearance requirements. The Influence of Line Voltage on Clearance For those power lines having a line to ground voltage of 750 Volts to 22-kV, the final minimum ground clearance for the 0 to 750 Volt supply conductor has to be increased further by an amount ranging from 2 ft to 18.5 ft (0.6 m to 5.6 m). For lines at higher voltages, the vertical clearance is increased by 0.4 inches (1 cm) for every kV increase in line to ground voltage above 22-kV. Note that the voltage used in these calculations of added electrical clearance are based on the maximum operating voltage of the power line that is typically 5% to 10% above the nominal operating voltage. As summary of the NESC requirements for a range of line to ground voltages is provided in Table 3-1. Table 3-1 Minimum Vertical Ground Clearances According to NESC C2-1997, Rule 232C. L-L/L-G
Basic Clearance @ 22-kV
kV
ft
M
69/40
18.5
5.6
138/80
18.5
161/93
Clearance Added for Voltage
Streets ft
m
0.7
19.2
5.8
5.6
2.1
20.6
6.3
18.5
5.6
2.5
21.0
6.4
230/133
18.5
5.6
3.9
22.2
6.8
345/200
18.5
5.6
7.0
25.5
7.8
500/290
18.5
5.6
9.9
28.4
8.7
765/440
18.5
5.6
15.5
34.0
10.4
Reduced Clearance for EHV Lines with Limited Switching Surge Levels For power lines exceeding 98-kV of line to ground voltage, the NESC safety code requires the allowable clearances to be calculated based on knowledge of the expected switching surge levels. If the switching surge level of the power line can be restrained to 2.2 PU, the clearance at EHV voltages may be decreased to values as shown in Table 3-2.
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Table 3-2 Minimum Vertical Ground Clearances According to NESC C2-1997, Rule232D Nominal Voltage L-L/L-G kV
Reference Height Listed in Table 232-3 ft
Alternate Clearance Adder
m
ft
m
Min Clearance for Streets ft
m
69/40
-
19.2
5.9
138/80
-
20.6
6.3
21.0
6.4
161/93 230/133
14
4.3
7.1
2.2
21.0
6.4
345/200
14
4.3
7.1
2.2
21.0
6.4
500/290
14
4.3
12.7
3.9
26.7
8.1
765/440
14
4.3
21.8
6.6
32.4
9.9
* In accordance with Rule 232D4, the clearance calculated based on Rule 232D2-3 cannot be less than the clearance calculated for 98-kV under Rule 232C.
Power System Conditions When Clearances Apply It is impossible to be certain that electrical clearances will be maintained under all foreseeable circumstances. For example, in many parts of the country, hurricanes or tornadoes may occur which might cause energized conductors to fall to the ground. However, the NESC safety code clearly outlines requirements to be used to design power lines or line upgrades likely not to result in unacceptable vertical clearances. The minimum conductor to ground clearances specified by the NESC safety code apply to all energized conductors in accordance with the three conditions specified in Rule 232A where the temperatures specified are that of the conductor not the surrounding air: •
50°C (122°F) with no wind displacement.
•
At the maximum operating temperature for which the line is designed to operate if greater than 50°C (122°F) without blowout resulting from wind.
•
0°C (32°F), without blowout resulting from wind and the NESC required equivalent radial thickness of ice.
Even in these days of heavily utilized transmission assets, it is unusual for power lines to carry electrical loads that cause the energized conductors to be more than 5 or 10°C (41°F or 50°F) above the ambient air temperature. However, given the relatively rare loss (outage) of a major generating station or EHV transmission circuit, the electrical loading on high voltage lines can unexpectedly increase resulting in significantly increased conductor temperatures. Thus, in accordance with the requirements of the NESC safety code, all power lines are designed to meet clearances “at the maximum operating temperature for which the line is designed to operate…”.
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Heavy ice loading on conductors are also relatively rare events. However, in any modern high voltage or extra high voltage transmission line, the energized conductor sag determined at 0 °C (32°F) in combination with the maximum ice loading typically results in a calculated sag of the conductor that is less than the sag determined at the high temperature condition. This is correct, even when that maximum operating temperature of the transmission line is only 50°C (122°F). Thus, the assurance of adequate vertical clearances is focused on investigating the behavior of the transmission line conductors at high temperatures not under heavy ice load. In most cases, transmission line operators typically meet the NESC safety code mandated minimum clearance requirements by limiting the current transferred on the energized conductors. The specification of any relationship (i.e., mathematical correlation) between the power line’s electrical current on the energized conductors and the resulting conductor temperature is left to the discretion of the operator. The NESC safety code describes the minimum horizontal and vertical clearances of energized conductors in considerable detail as a function of the conductor to ground voltage and potentially dangerous activities. The NESC safety code also prescribes the set of conditions under which the mandated clearance minimums must be met. However, the NESC safety code does not specify or recommend a method to be used to calculate the operating temperature of the energized conductor, the method to be used to determine the physical position of the conductor above ground and its relationship to the maximum operating temperature, and methods to be used to confirm the adequacy of the conductor’s ground clearance in those rare occasions of high electrical loading. Consequently, methods used to assure adequate ground clearance vary widely among transmission line operators. Examples of Clearance Assurance Methods The Rural Electrification Administration (REA) Manual, whose specifications cover power lines up to 230-kV, includes specific provisions to generate minimum conductor to ground clearances. It should be noted that the use of the REA’s specifications result in clearances that are about 10% greater than those found in the NESC safety code (e.g. 25.0 ft (7.6m) at 230-kV versus the NESC requirement of 22.2ft (6.8 m)). Based on the difference, one may conclude that the REA manual recommends the use of a buffer of approximately 3-ft (0.9 m) in designing overhead lines. The REA manual also includes a more specific interpretation of what the maximum conductor temperature should be (i.e. 75°C normal and 100°C for emergency operating conditions). Also, the REA manual more provides guidance on how the emergency electrical loading should be estimated (i.e. “…the line loads that would be sustained when the worst combination of one line and one generator outage occurs [over the life of the line]). However, as in the case of the NESC safety code, the REA manual (1992 Edition) does not describe how the relationship between line current and conductor temperature should be determined. Installation Buffers on New Lines There is always some uncertainty associated with respect to the actual installation sags, the exact height of the insulated support points, and the amount of permanent conductor elongation that is likely to occur over the service life of the transmission line. Therefore, it is common for power
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line designers to include a clearance buffer (as a safety margin) when a power line is designed and constructed. This clearance buffer typically ranges from 1 to 2 m (3 to 6 ft) or more. In the process of locating structures in all but the most level terrain, the goal of the designer is typically to find the lowest cost solution (based on construction cost) rather than to minimize excess clearance. Thus, upon completion of the construction it is common that the actual ground to conductor clearance under worst-case conditions is well above the code specified combined minimum clearance and construction buffer. Upgrading Buffers On older existing transmission lines, the structure placement along the right of way and the final sag of the conductor is measurable. Thus the required buffer can be reduced. However, in this process there are certain irreducible uncertainties and risks that stipulate that some clearance safety margin must be maintained. The traditional method of determining vertical and horizontal conductor to ground clearances for existing transmission lines involves standard surveying methods to accurately measure the position of the conductor attachment points and the conductor sags at the span mid-point for one or more spans in each tension section of the transmission line. These measurements are typically taken with the transmission line out of service so that the line’s conductor is more or less at the ambient air temperature (some consideration has to be given to the influence of solar radiation). In such detailed field surveys, vertical position errors of up to a foot (0.3m) are easily made in determining the catenary’s position and the attachment heights. Additional errors may be introduced and should be expected in determining the actual conductor to ground clearance since the survey of the ground profile is only checked at a few points along the transmission line. In more recent years, several photographic and laser based methods have been developed that are suitable for the survey of the right of way, support structures, and conductors. These survey methods are capable of determining the position of all attachment points at all support structures and are also capable of providing a complete description of the catenaries profile of all phase conductors and shield wires. Based on utility evaluations, the accuracy of such laser-based surveys is better than the accuracy achieved by conventional surveying methods. Such laser-based measurements are seldom done with the transmission line out of service so that the line’s conductor temperature at the time of the survey measurements must be either calculated or measured. While the results of such detailed survey activity are very impressive and likely to convince the novice that safety buffers can be eliminated or reduced when upgrading existing lines, industry experience has shown this not to be the case. Knowing the exact ground clearance with perfect certainty (if achievable) at the conclusion of a laser survey does not mean that one can be certain of providing adequate clearances under all conditions. Many other sources of uncertainty exist and need to be considered prior to a reduction or elimination of the safety buffer. Most of these uncertainties arise from the difficulties associated with determining the maximum electrical loading of the power line.
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Probabilistic Clearances In the United States, electrical clearances imposed by the safety codes are deterministic. That is, the minimum electrical clearances specified in the various safety codes must be met under all foreseeable operating conditions. It is not generally considered adequate to meet such clearances a certain percentage of the time (e.g. 99% probability). In 1990, a task force of industry representatives was set up under the Institute of Electrical and Electronics Engineers (IEEE) Working Group on the Calculation of Bare Overhead Conductor Temperatures to review Section 23 of the NESC with regard to the electrical clearances at high conductor temperatures. The conclusion of this Task Force (TF) was that the present clearance definitions in this section of the Code were sufficiently clear to guide transmission operators in maintaining adequate safe ground clearance under all operating conditions. The TF noted that the Bonneville Power Administration (BPA) which had been considering the use of probabilistic clearances for some time had concluded that to attain a 98% probability of compliance with safety code mandated clearances, the present 3 ft (0.9 m) design buffer needed to be increased to about 5 ft (1.5 m). The conclusion of the TF was that this change was “probably not justified economically”. Jerry Redding of BPA has written an IEEE Transactions paper, which presents a method of calculating the probability of line flashover to “conflicting activity” under it. On the contrary, the NESC safety code essentially assumes that the probability of flashover is negligible at a line to ground voltage of 22-kV as long as the energized conductor is 4 ft (1.2 m) from the conflicting activity and assumes that the probability of flashover remains negligible as long as the spacing is increased by 0.4 inches (1 cm) for every kV increase in voltage. The BPA model assumes a probability of flashover of the form: E f = Ap ⋅ Cp ⋅ Tp ⋅ Fp in which the parameter Ef equals the probability of flashover from the energized transmission line conductor to the conflicting activity.
Electrical Losses Operation of transmission lines at high temperatures is a clear indication that electric losses are significant (high temperatures are due to Ohmic (I2R) losses). The cost of these electrical losses should be considered as part of the process of evaluating transmission line uprating alternatives, but electrical losses are seldom a significant constraint on line uprating. This is due to the fact that thermally limited lines are usually short and that the high loading events on the power line are usually of limited duration and frequency. The flow of electrical current on the phase conductors results in the loss of electrical energy due to conductor heating. For example, consider a 10-mile long (16-km), 115-kV three-phase transmission line with 26/7 ACSR Drake conductor. Assume that the current on the phases of the line is constant and equal to the static thermal rating of 26/7 ACSR Drake conductor (the static rating is 990 Amperes for a maximum allowable conductor temperature of 100°C without sun, 25°C ambient air temperature, and a 2 ft/sec (0.6 m/sec) crosswind). For the example,
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assume also that these “worst case” thermal rating weather conditions persist (remain constant). Finally, consider that the cost of power equals $30 per MW-hr. Loss Calculations – Examples At 990 Amperes per phase, the transmission line is carrying a load at its full thermal capacity of 197 MVA (1.732*.990*115 = 197) and the temperature of the phase conductors is at 100oC. The resistance of the 26/7 ACSR Drake at 100oC is 0.1406ohms/mile (0.0874 ohms/km), and so the total of losses in the three phase conductors is calculated as 413 kW per mile (257 kW per km) (0.1406*990^2*3/1000 = 413). At a power factor of 0.95, the 115-kV line is transmitting 187 Megawatts, so that the electrical loss amount to 0.22% of the real power transmitted per mile of the transmission line. The cost of the transmission line losses operating at these conditions is therefore $12/hr-mi ($7.71/hr-km) (0.413GW/mi * $30/GW-hr). If the transmission line operating voltage is increased to 230-kV (assuming the use of the existing ACSR Drake conductor), then the thermal rating of the line is doubled. However, if the uprated transmission line transmits the same 187 MW as before, the phase current is only 445 Amperes. Therefore, if operated at 230-kV, the conductor temperature drops to approximately 34°C (93°F), the resistance per mile is reduced to 0.1203 ohms/mile (0.0747 ohms/km), and the losses per mile are reduced (by 83%) to 71 kW/mile (44 kW/km). These electric losses amount to 0.0038% of the transmitted power (187 MW) and the same $12/hr-mile ($7.71/hr-km). Even if the phases are carrying a load of 394 MVA (the line’s new thermal limit), the electrical losses would only be 0.10% of the real transmitted power per mile of transmission line or $24/hr-mile ($14.92/hr-km). If the 115-kV line were thermally uprated to 235 MVA (instead of 197 MVA) by increasing the maximum allowable conductor temperature to 100°C (212°F) through raising structures and retensioning, then the maximum allowable current per phase would be 1180 Amperes. If, as used in the preceding calculation, the line current equals the new thermal rating, then the electric line losses would increase by 54% from 413 kW/mile to 637 kW/mile (257 kW/km to 396 kW/km), which is 0.29% of the transmitted power per mile or $18/hr-mile ($11/hr-km). Loss Calculations – Use of Load and Loss Factors Unfortunately, the comparison of electrical losses for various uprating alternatives is not quite this straightforward for a real transmission line. The transmission line loading varies with the season, the weather and the time of day. For many power lines, even those that are candidates for uprating, the normal load may be well below the thermal capacity of the line (approaching the thermal capacity of the line only under occasional contingency loadings due to emergency operation). In order to account for the variation in line load over time, consider the following definitions: •
"Peak Load" is the load that occurs under normal operation of the transmission line.
•
"Peak Contingency Load" is the load that occurs only rarely, under emergency operation of the transmission line.
3-12
•
“Average Load" is the average line load over a period of normal operation.
Since the "Peak Contingency Load" occurs only rarely, the transmission line electric losses that occur during these contingency periods will be neglected and are omitted from the discussions. It is assumed that the peak and average line loadings are known or may be bounded for each future year of the uprated line. The line load factor (LoadF) for each of those future years is defined as the ratio of average to peak line load over the year. In order to calculate the present worth of line losses, however, one needs to know the loss factor (LossF) - the ratio of average annual electrical losses to peak losses - rather than the load factor. If the average current on a conductor over one year is 500 Amperes and the peak current over the same period is 1000 Amperes, then the load factor is 0.50. If the current is quite constant at 500 Amperes except for brief excursions (short time increases) to 1000 Amperes, then the loss factor for the conductor is 0.25. The relationship of load factor to loss factor for a transformer depends on the ratio of load losses to core losses. Since transformer core losses depend on the circuit voltage (not the circuit load), it is possible that the loss factor of a lightly loaded transformer can exceed the load factor. In many cases, the load factor and the loss factor are often empirically related by a formula such as: LossF = 0.15 ⋅ LoadF + 0.85 ⋅ LoadF 2 Clearly, the present value of $100 in the 15th year after a line is uprated is less than the present value of $100 in losses during the first year after uprating. The present worth of line losses, n years after the uprating occurs, depends upon the interest rate, I, as given by the formula: i PWLosses = ( ADCn + AECn ) ⋅ 1 + 100
−n
Where the factors ADCn and AECn are the annual demand charge and annual energy charges for the nth year of the line's life. The parameter “i” is the assumed annual interest rate and “n” is the year counting from the time when the line is uprated.
Environmental Effects The public considers overhead transmission lines as very visible and imposing and, though most power industry engineers have difficulty in understanding why, unattractive. Thus, one of the primary environmental effects of any transmission line is their visual impact on people and their surroundings. A great deal of effort has been expended by the industry in the past to make transmission lines more visually acceptable. Such efforts have led to decidedly mixed results. Because lines are highly visible and perceived as unattractive, they can have a negative impact on property values. This is typically much less of an issue with the modification of existing lines than with new lines.
3-13
Figure 3-4 shows a comparison of the relative importance of some of the major environmental issues involving overhead lines as determined by a survey. It is interesting that the top three factors are primarily the result of human perception and beliefs while the three least important issues are matters of physics. Various attempts have been made in the industry to reduce the visual impact of power lines and the corresponding impact on property values. For example, there have been design competitions motivating architects and designers to find more visually acceptable structures and research into methods of compacting high voltage lines so they look more like distribution lines.
Figure 3-4 Median Survey Results as to Why People Oppose Transmission Lines
Probably the most effective way to reduce public opposition to transmission lines concerns putting them away from where people live and work. Clearly, this is not always possible, but as shown in Table 3-3, can be quite effective.
3-14
Table 3-3 The Impact of Distance on Public Opposition to Power Transmission Lines Distance from Line Feeling
Less than 1 mile
More than 1 mile
Like it
2.3%
3.2%
Don’t care
32.6%
71.3%
Dislike it
65.1%
25.3%
In the specific case of uprating, a variation on the Hippocratic oath “To do no harm” makes sense. Specifically, it appears that uprating techniques that do not raise the height of the support structures or make conductors more visible from a distance are preferred in achieving public acceptance. This guide emphasizes line uprating methods where the voltage of the line remains the same but current flow is increased. Most of the techniques covered herein will leave the original ground level electric field, electric induction, corona discharge levels and audible and radio noise levels unchanged. However, it should be noted that the ground level magnetic field and magnetic induction levels increase as the transmission line currents are increased. Both environmental effects are linear proportional to the current so that the maximum original levels are easily estimated by scaling the effects with the increase in rating.
Structure & Foundation Loads Transmission lines are typically designed to survive reasonably conservative worst-case structure and foundation loads and the resulting conductor tensions. The weather conditions, which result in the maximum conductor tensions, are not necessarily those that yield the most challenging structure and foundation loads. In the discussion of line uprating (Section 4), it is assumed that the existing transmission line has managed to survive 40 years or more of ice and wind loads with an acceptable (or non-existing) structure and foundation failure rate. If this assumption is not true, then the issues of uprating can only be considered after the line is carefully reviewed and structurally reinforced. In contrast, if the conductors of the existing transmission line have frequently been observed to fail, the reconductoring may increase the capacity of the line and improve its service reliability. Any attempt to increase the power transfer capacity of a transmission line with poor performance characteristics without reconductoring and reconditioning of related components is likely to worsen an already bad situation. Before undertaking any uprating project, a review of the existing structures and operating records of the line is required. If failures at angle or dead-end structures have occurred, any attempt at increasing the everyday installed tension of the conductors is unlikely to succeed. Similarly, if occasional high temperature operations have yielded splice failures, increasing the transmission line’s operating temperature without replacing or inspecting the line is not advisable. Finally, if
3-15
a review of structure and foundation capacity indicates that the line was conservatively designed exhibiting significant reserve capacity and that failures have not been observed, the line may be a prime candidate for reconductoring with a larger diameter conductor. When a conductor is ice covered and/or is exposed to the wind, the effective conductor weight per unit length increases. During occasions of heavy icing and/or the presence of significant wind load, the conductor catenary tension increases dramatically along with the loads on angle and dead-end structures. Both the conductor and its supports can fail unless these high-tension conditions are considered in the line design. The National Electric Safety Code (NESC) suggests certain combinations of ice and wind corresponding to heavy, medium, and light loading regions of the United States. Figure 3-5 and Figure 3-6 show maps of the United States indicating those areas. The combinations of ice and wind load areas corresponding to the loading districts that are listed in Table 3-4. Recently, changes have been made to the estimates of the expected line ice loading and to the calculation methods to be used for combined ice and wind loads. Table 3-4 Definition of NESC Loading Areas Loading Districts Heavy
Medium
Light
Extreme Wind Loading
Radial thickness of ice(in)
12.5
6.5
0
0
Radial thickness of ice(mm)
318
165
0
0
Horizontal wind pressure(lb/ft )
4
4
9
See Figure3-6
Horizontal wind pressure(Pa)
190
190
430
See Figure3-6
Temperature(°F)
0
+15
+30
+60
Temperature(°C)
-18
-10
-1
+15
Constant to be added to the resultant (all conductors) (Lb/ft)
0.30
0.20
0.05
0.0
Constant to be added to the resultant (all conductors) (N/m)
4.40
2.50
0.70
0.0
2
The NESC safety code also suggests that increased conductor loads due to high wind loads but no ice should be considered. Figure 3-6 shows the suggested wind pressure as a function of geographical area for the United States. Utilities in very heavy icing areas may use larger estimated glaze ice thickness of as much as 2 to 3 inches (5 to 7.6 cm) in order to calculate the iced conductor weight. This is especially true if they have experienced extensive transmission line failures due to ice loading in excess of those minimum recommended values required by the NESC safety code. Similarly, utilities in regions where hurricane winds occur may use wind loads as high as 34 lb/ft2 (1.63 KPa).
3-16
Figure 3-5 NESC Transmission Line Loading Areas
Figure 3-6 NESC Wind Pressure Values for Transmission Line Design
3-17
The NESC tables and charts indicate that the degree of ice and wind loading varies from one region to the other. Some areas may experience heavy icing, whereas other areas may be prone to extremely high winds. Regardless of the type of load, all loads must be accounted for in the line design process to prevent the unexpected failure of the transmission line. A brief discussion of the effects of both the individual and combined components of ice and wind loading is provided in the following sections. Ice Loading The formation of ice on overhead conductors may take several physical forms such as glaze ice, rime ice, or wet snow. The impact of lower density ice formation is usually considered in the design of line sections at high altitudes. The formation of ice on overhead conductors has the following influence on line design: •
Ice loads determine the maximum vertical conductor loads that structures and foundations must withstand.
•
In combination with simultaneous wind loads, ice loads also determine the maximum transverse loads on structures.
•
In regions of heavy ice loads, the maximum sags and the permanent increase in sag with time (difference between initial and final sags) may be due to ice loading.
Ice loads for use in designing lines are normally derived on the basis of past experience, code requirements, state regulations, and analysis of historical weather data. Mean recurrence intervals for heavy ice loadings are a function of local conditions along various routings. Line design software is a tool typically used to investigate the impact of a variety of assumptions concerning ice loading. The calculation of ice loads on conductors is normally done with an assumed glaze ice density of 57 lb/ft3 (913 kg/m3). The following equation calculates the weight of ice per unit length of conductor: wice (lb / ft ) = 1.244 ⋅ t (in) ⋅ [Dc (in) + t (in)]
wice ( N / m) = 0.0281 ⋅ t (mm) ⋅ [Dc (mm) + t (mm)] Where: t
= Radial Thickness of Ice
Dc
= Conductor Outside Diameter
wice
= Resultant Weight of Ice
The ratio of iced weight to bare wire weight depends strongly upon the conductor diameter. As shown in Table 3-5, for three different conductors covered with 0.5-in radial glaze ice, this ratio ranges from 4.8 for #1/0 AWG to 1.6 for 1590-kcmil conductors. Therefore, smaller diameter conductors may need to have a higher elastic modulus and higher tensile strength than larger diameter conductors in heavy ice and wind loading areas to limit the sag.
3-18
Table 3-5 Ratio of Iced to Bare Conductor Weight ACSR Conductor
D
wbare
wice
wbare+wice --------wbare
(in)
(lb/ft)
(lb/ft)
#1/0AWG-6/1 “Raven”
0.398
0.1452
0.559
4.8
47-kcmil-26/7 “Hawk”
0.858
0.6570
0.845
2.3
1590-kcmil-54/19 “Falcon”
1.545
2.044
1.272
1.6
Wind loads on overhead conductor influences the design in a number of ways: •
The maximum span between structures may be determined by the need for horizontal clearance to edge of right-of-way during moderate winds.
•
The maximum transverse loads for tangent and small angle suspension structures are often determined by infrequent high wind-speed loading.
•
Wind loading determines permanent increase in conductor sag in areas of light ice loads.
Wind pressure load on conductors, Pw, is commonly specified in lb/ft2. The following equation gives the relationship between Pw and wind velocity: Pw (lb / ft 2 ) = 0.00256 ⋅ [Vw (mph)]
2
Pw ( Pascals) = 0.0473 ⋅ [Vw (km / h)]
2
Where Vw = the wind speed in miles per hour.
The wind load per unit length of conductor, Ww, is equal to the wind pressure load, Pw, multiplied by the conductor diameter (including radial ice of thickness t, if any):
Ww (lb / ft ) = Pw ( psf )
[Dc (in) + 2 ⋅ t (in)]
12 [D (mm) + 2 ⋅ t (mm)] Ww ( N / m) = Pw ( Pascals) ⋅ c 1000
3-19
Combined Ice and Wind Loading - If the conductor weight is to include ice and wind loading, the resultant magnitude of the loads must be determined. The following equation gives the weight of a conductor under both ice and wind loading: ww + i = ( wb + wi ) 2 + (Ww ) 2 Where wb
= bare conductor weight per unit length, lbs/ft
wi
= weight of ice per unit length, lbs/ft
ww
= wind load per unit length, lbs/ft
ww+i
= resultant of ice and wind loads, lbs/ft
The NESC prescribes a safety factor, K, in pounds per foot, dependent upon loading district, that is added to the resultant ice and wind loading when performing sag and tension calculations. Therefore, the total resultant conductor weight, w, is: w = ww + i + K
Wind-Induced Fatigue & Flashover This section describes the types of wind-induced motion to which transmission line conductors are prone. These motions result in flashovers between phases, or flashovers between a phase conductor and ground, or cause fatigue damage in conductors, or even cause premature wear in support hardware. Control methods involve the following options: limiting the everyday tension to moderate levels, or applying dampers (aeolian vibration) and maintaining sufficient phase-tophase distances (ice galloping). These traditional methods may make certain uprating method difficult or impossible. Overhead transmission lines are often subjected to wind-induced conductor motion. Since conductor cost may rival all other line cost. Hence, transmission line designers must consider the effect of shortened conductor life due to wind-induced conductor motion. In the simplest case, wind can cause the conductor catenary to swing in the direction of the wind. This conductor "blowout" requires conductor clearances be selected to maintain minimum clearance from both the edge of the right-of-way and supporting structures under maximum blowout conditions. Conductors on overhead transmission lines commonly experience a variety of wind-induced motions. The design of new transmission lines must allow for wind- and combined wind/iceinduced conductor and insulator movements. Aeolian vibration is a major factor in the maximum allowable unloaded conductor tension that determines structure spacing and/or height. Ice galloping is a major determinant of minimum phase spacing, especially for double-circuit and delta-phase arrangements. Sub conductor oscillation is an important consideration in bundle sub conductor spacing, spacer selection, and choice of sub span length. Table 3-6 compares the most common types of oscillatory motion induced by wind.
3-20
The most common type of wind-induced motion is aeolian vibration. It occurs at relatively low wind speeds and is cumulative in nature. Broken conductor strands that result from aeolian vibration may take many years to occur. When broken strands do occur, the vibration is normally controlled (1) by providing vibration dampers, (2) by stringing conductor at relatively low tension levels to maximize its self-damping, or (3) by using special types of conductor such as SDC, VR, or ACSS. Ice galloping occurs with both single and bundled conductors and requires high winds and ice on the conductors. If uncontrolled, it can yield both phase-to-phase flashovers, due to reduced spacing at mid-span, and hardware damage. A variety of control methods have been proposed and tested to varying degrees to limit flashovers due to ice galloping. The most common control method is to allow sufficient phase-to-phase spacing to avoid flashovers when galloping does occur. In certain instances, extended ice galloping of large amplitude has caused structural failures. Sub conductor oscillation only occurs for bundled phase conductors when wind speeds exceed a certain critical velocity .If uncontrolled, it can result in fatigue damage to spacers and suspension hardware. Oscillations are controlled by keeping bundled conductors at a spacing-to-diameter ratio of about 20 or more and by avoiding uniform spacer spacing. Transmission lines must be designed not only to provide adequate vertical clearance for electrical and safety considerations, but also to allow for adequate horizontal clearance to tall objects and buildings at the edge of the ROW under high wind conditions. This conductor displacement is termed conductor blowout. The maximum displacement of the outermost conductors from the center of the ROW under high wind conditions can be one of the most important variables in determining ROW width. Conductor blowout is primarily a function of conductor weight and the wind force perpendicular to the conductor. However, the calculation of conductor blowout should also include the lateral movement of the suspension insulators. The following equation estimates the horizontal wind force acting on a conductor:: (equation is missing)
Connectors & Conductor Hardware As discussed in Section 5, conductor connectors and certain types of ferrous hardware can limit line loading. Connectors used in transmission lines include limited tension connectors and full tension connectors. Limited tension connectors are primarily designed to join conductors that are under little or no mechanical tension, and full tension connectors are designed to provide adequate mechanical strength to fully develop 95% of the conductor's strength. Properly made connections run cooler than the conductors that they connect. This is due to their lower resistance, greater diameter, and greater mass. Under high temperature conditions, improperly made connections can fail quickly and result in line outages or even endangering the public. Connectors’ age naturally with time and use, their resistance gradually increasing over time, but corrosion or improper assembly can lead to rapid increases in resistance and operating temperature. Consistent with the IEEE Draft Standard, connectors should be “considered failed if their operating temperature exceeds the temperature of the conductor to which they are attached. It
3-21
can be argued a connector operating in this mode has previously failed, and it can also be argued a connector has not failed until the conductor has parted interrupting electrical continuity. However, “failed” field connectors are very difficult to detect until operating in thermal failure mode, and such operation is usually a precursor to imminent conductor parting.” Thus, the condition of the connectors in an existing line can be a significant constraint on the engineer’s ability to uprate the line with minimal capital investment. Failures of such connectors after re-rating can be a source of embarrassment and service interruption costs. Table 3-6 Cyclic, Wind-induced Conductor Motions
Types of Overhead Lines Affected
Approx. Frequency Range, Hz Approx. Range of Vibration Amplitudes (Peak-to-peak, Expressed in conductor diameters)
Aeolian Vibration
Ice Galloping
Subconductor Oscillation
All
All
Limited to lines with bundled conductors
3 to 150
0.08 to 3
0.15 to 10
0.01 to 1.0
5 to 300
0.5 to 80
Steady
Steady
Steady
1 to 7 m/sec (2 to 15 mph)
7 to 18 m/sec (15 to 40 mph)
4 to 18 m/sec (10 to 40 mph)
Bare or uniformly iced
Asymmetrical ice deposits
Bare, Dry
3 months to 20 years
1 to 48 hours
1 month to 8+ years
Conductor fatigue due to cyclic bending
High dynamic loads on structure and hardware
Conductor clashing, accelerated wear in hardware
Weather Conditions Favoring Conductor Motion Wind Character: Wind Velocity:
Conductor Surface: Damage Approx. Time Required for Severe Damage to Develop:
Direct Causes of Damage:
3-22
4 CALCULATION OF OVERHEAD LINE THERMAL RATINGS Rating Definitions The power conductors of overhead lines are self-supporting and energized at high voltage. They are stranded from wires of aluminum or copper, which may be reinforced with a steel core. As the current flowing through a conductor increases, the temperature increases, and it elongates. This elongation increases the sag of the conductor between support points, decreasing the clearance to people, ground, other conductors, buildings, and vehicles under the line. Beyond certain “maximum allowable” sag, the line may flashover, resulting in either a power supply outage or injury to the public. If the conductor temperature remains high for an extended period of time, the strength of the conductor and tensioned connectors may decrease, resulting in mechanical failure during the next occurrence of ice or high wind loading. To avoid excessive sag or loss of strength, a “maximum allowable conductor temperature” is typically specified, and the conductor temperature is kept below this maximum by placing limits on the level and duration of power transferred by the line (MVA or Amperes). If such limits are based on worst-case weather conditions, they are called static ratings, and if based on actual weather conditions, they are called dynamic ratings. High Temperature Clearance to People, Buildings, & Lines Modern transmission conductors are typically stranded from aluminum wires with a steel core added where increased strength is required. The temperature limit on all-aluminum or ACSR conductors is based on the maximum sag or maximum loss of strength in the aluminum. Temperature limits in use today range from 50°C to 150°C (122°F to 302°F). The temperature limit is normally selected at the time the line is designed. The higher this temperature, the higher the thermal capacity of the line, the maximum conductor sag, and the higher (or closer) the structures required to maintain ground clearance. Annealing of Aluminum and Copper If aluminum or copper conductor temperatures remain high (above 95 °C, or 203 °F) for an extended period of time, the strength of the conductors and tensioned connectors may decrease, which eventually results in mechanical failure during the next ice or high wind occurrence. Generally, rating duration’s are kept short if maximum conductor temperatures are high (e.g. 4 hour maximum at 115 °C (239 °F) and 15 minutes at 125 °C (257 °F)).
4-1
How Weather Changes Affect Line Ratings The impact of changes in weather parameters upon thermal line ratings depends on the specific rating situation. In this discussion, consider an overhead line with 795 kcmil, 26/7, “Drake” ACSR conductor, whose static rating is based upon a maximum allowable conductor temperature of 100oC with an air temperature of 40oC, full summer sun, and a wind blowing perpendicular to the conductor axis at 2 ft/sec. The static rating under these conditions is 1000 Amperes. Clearly, if the current in this conductor is a 1000 Amperes with the assumed weather conditions, the conductor temperature is 100oC. Table 4-1 shows how the conductor temperature changes for small changes in weather conditions. For example, the conductor temperature drops to 92oC if there is no solar heating. The table also shows how the thermal rating (i.e. the current which yields a temperature of 100oC) changes with small changes in weather. Note that, with the conductor at a reasonably high temperature and near “worst-case” heat transfer conditions, the overhead line rating and conductor temperature are very sensitive to wind direction, modestly sensitive to changes in wind speed and solar heating and less affected by small changes in air temperature. Other minor factors are gradual changes in emissivity and absorptivity of the conductor with age and seasonal shifts in solar heating. Table 4-1 Variation in Conductor Temperature and Rating with Weather Conditions (IEEE738) Range in Weather Conditions
o
Line Rating @ 100 C
Conductor Temperature at 1000 amps
(Amperes)
(°C)
(°F)
None
1000
100
212
39°C
1010
99
210
No sun
1070
92
198
3ft/sec (0.91m/sec)
1090
90
194
Parallel wind
750
133
271
Heat Balance Methods Around the world, utilities perform overhead line rating calculations in essentially the same way: by setting the heat input from Ohmic losses and solar heating equal to the heat loss due to convection and radiation. The specific formulas used to determine the heat balance terms vary somewhat but normally one of three methods is used – the IEEE method, the CIGRE method, or the EPRI DYNAMP method. Given the same assumed wind speed and direction, the same conductor temperature and the same conductor electrical and physical parameters, the thermal rating found with the three methods is similar if not identical. The following sections show an example of thermal rating calculations for the three methods.
4-2
Definition of Variables for Heat Balance Calculations For the rating calculations described in this guide, it is customary in the United States to use a non-standard combination of units that are referred to throughout this document as “US. Units”. SI units are preferred. Table 4-2 Definitions of Thermal Rating Equation Variables Description Symbol
SI Units 2
US Units 2
m/ lineal m
ft / lineal ft
m
ft
J/kg·°C
J/lb·°C
mm
in
degrees
degrees
Elevation of conductor above sea level
m
ft
I
Conductor current
A
A
Ii
Initial current before step change
A
A
If
Final current after step change
A
A
Kangle
Wind direction factor
-
-
Ksolar
Solar Altitude Correction Factor
-
-
Thermal conductivity of air @ temperature, Tfilm
W/m-°C
W/ft-°C
Lat
Degrees of Latitude
degrees
degrees
M
Month of the year(January=1,February=2,etc.)
-
-
J/m·°C
J/ft·°C
kg/m
lb/ft
W/lineal m W/lineal m W/lineal m
W/lineal ft W/lineal ft W/lineal ft
A’
Projected area of conductor
C
Solar Azimuth Constant
Cpi
Specific heat of i conductor material
D
Conduct or diameter
Hc
Altitude of Sun
He
kf
mCp
th
Total heat capacity of conductor th
mi
Weight per unit length of i conductor material
N
Day of the year (January 21=21,February 12=43, etc.)
qc
Convected heat loss rate
qr
Radiated heat loss rate
qs
Heat gain rate from Sun
Qs
Total solar and sky radiated heatflux rate
R(Tc)
W/m
AC Resistance of conductor @ temperature, Tc
4-3
ς/m
2
2
W/ft ς/ft
Ta
Ambient air temperature
°C
°C
Tc
Conductor temperature
°C
°C
Thigh
Maximum conductor temperature for which AC resistance is specified
°C
°C
Vw
Speed of air stream at conductor
m/s
ft/h
Y
Year
-
-
Zc
Azimuth of Sun
degrees
degrees
Zl
Azimuth of line
degrees
degrees
∆t
Time step used in transient calculation
s
s
∆Tc
Conductor temperature increment corresponding to time step
°C
°C
-
-
degrees
degrees
-
-
sec
sec
Angle between wind and axis of conductor
degrees
degrees
β
Angle between wind and perpendicular to conduct axis
Degrees
degrees
ρf
Density of air
θ
Effective angle of incidence of the Sun’s rays
degrees
degrees
Absolute(dynamic)viscosity of air
N/m-s
lb/ft-hr
ω
Hours from local sun noon times 15
degrees
degrees
χ
Solar Azimuth Variable
None
none
;
Solar absorptivity(.23to.91)
δ
Solar declination(0to90)
ε
Emissivity(.23to.91)
τ
Thermal time constant of the conductor
f
kg/m
3
3
lb/ft
Radiation Radiation of heat from an overhead conductor is modeled similarly in the three major heat balance methods. The equation for radiation heat loss is:
T + 273 4 T + 273 4 a ⋅ ⋅ ⋅ = 0. 0 1 7 8 D ε c qr − W /m 100 100
4-4
T + 273 4 T + 273 4 a q r = 0.138⋅ D⋅ ε ⋅ c − W / ft 100 100 As an example of radiation heat loss from a bare overhead conductor, consider Drake ACSR at 100oC and an air temperature of 40oC: 4 4 Tc + 273 Ta + 273 − q = 0.138 ⋅ D ⋅ε 100 100 r
4 4 Tc + 273 Ta + 273 q = 0.0178 ⋅ D ⋅ε − 100 100 r
where
where D ε Ta Tc
= = = =
D ε Tc Ta
28.14 mm 0.5 40 °C 100 °C
4 4 373 313 − q = 0.0178 ⋅ 28.14 ⋅ 0.5⋅ r 100 100
qr = 24.44
= = = =
1.108 in 0.5 100 °C 40 °C
4 4 373 313 − q = 0.138 ⋅ 1.108 ⋅ 0.5⋅ r 100 100
W/m
qr = 7.461=
W/ft
Convection Natural Convection With zero wind speed, natural convection occurs, where the rate of heat loss is:
q c = 0.0205⋅ρ f0.5 ⋅ D 0.75⋅ ( T c - T a )1.25 W / m
q c = 0.283⋅ ρ f0.5 ⋅ D 0.75⋅ ( T c - T a )1.25 W / ft
4-5
It has been argued that, at low wind speeds, the convection-cooling rate should be calculated as the vector sum of the wind speed and a “natural” wind speed, see [B22]. In most cases, this causes a needless complication with little change in line rating. For both forced and natural convection, air density (ρf), air viscosity (µ f), and coefficient of thermal conductivity of air (kf) are taken at Tfilm, where T film =
Tc + Ta 2
Taking our example of Drake ACSR at 100oC, the natural convection heat loss is calculated by means of the following two equations: q c = 0.0205⋅ ρ 0f .5 ⋅ D 0.75 ⋅(Tc −Ta )1.25 (5s ) q c = 0.283⋅ ρ 0f .5 ⋅(Tc −Ta )1.25 where: D Tc Ta
where: = = =
Tfilm = ρ
f
qc
28.14 mm 100°C 40°C 100 + 40 2
D TC Ta
T film =
= 70o C
3
ρ =
= 1.029 kg/m (see Table 1u) 0.5
= 0.0205 (1.029) (28.14) = 42.4 W/m
= 1.108 in. o = 100 C o = 40 C
0.75
(100–40)
f
1.25
qc =
100 + 40 = 70 o C 2 3
0.0643 lb/ft (Table 1s) 0.5
0.283 (0.0643) (1.108) = 12.9 W/ft
0.75
(100-40)
1.25
Forced Convection With the IEEE 738 method, forced convection is calculated with two separate formulas and the larger of the two values for forced convection heat loss is used. 0.52 D V ρ ⋅ ⋅ f w ⋅ k f ⋅ (Tc − Ta ) W / m q = 1.01+ 0.0372⋅ c1 µ f
4-6
0.52 D ⋅ ρ f ⋅ Vw ⋅ k ⋅ (T − T ) q = 1.01+ 0.371⋅ f c a c1 µ f
D ⋅ ρ ⋅V w f q = 0 . 0119 ⋅ c2 µ f
0 .6
D ⋅ ρ ⋅V w f q = 0 . 1695 ⋅ c2 µ f
0 .6
W / ft
⋅k
f
⋅ T −T c a
(
)
W /m
⋅k
f
⋅ T −T c a
(
)
W / ft
The first equations apply at low winds but are too low at high speeds. The following equations apply at high wind speeds, being too low at low wind speeds. At any wind speed, the larger of the two calculated convection heat loss rates is used. The convective heat loss rate is multiplied by the wind direction factor, Kangle, where φ is the angle between the wind direction and the conductor axis: K angle = 1.194 - c os( φ ) + 0.194 cos (2φ ) + 0.368 sin (2φ )
Alternatively, the wind direction factor may be expressed as a function of the angle, ω, between the wind direction and a perpendicular to the conductor axis. This angle is the complement of φ, and the wind direction factor becomes: K angle = 1.194 − sin (ω ) − 0.194 cos (2ω ) + 0.368 sin (2ω )
Referring once again to our example of Drake ACSR at 100oC we have: 0.52 D⋅ ρ f ⋅ V w ⋅ ⋅( − ) w / m qc1 = 1.01 + 0.0372⋅ k f Tc Ta µf
D ⋅ ρ ⋅V f w q = 0 .0119 ⋅ c2 µ f
0.6 ⋅k
f
(
⋅ T −T c a
)
w/m
0.52 D⋅ ρ f ⋅ V w ⋅ ⋅( - ) w / m qc1 = 1.01 + 0.0372⋅ k f Tc Ta µf
D ⋅ ρ ⋅V f w q = 0 . 1695 ⋅ c2 µ f
4-7
0 .6 ⋅k
f
(
⋅ T −T c a
) w / ft
where:
where:
D = 28.14 mm Vw = 0.61m/sec o Tc = 100 C o Ta = 40 C
D = 1.108 in Vw = 2 ft/s ⋅ 3600 sec/hr o Tc = 100 C o Ta = 40 C
Tfilm =
100 + 40 2
= 70o C
Tfilm =
µf = 2.04E-5 Pa - sec (Table 1s) 3 (Table 1s) ρf = 1.029 kg/m Kf = 0.0295 w/m - C (Table 1s)
W/m
28 .14⋅1.029 ⋅.6096 q c 2 = 0.0119 ⋅ 2.04⋅10 − 5 .0295 ⋅ (100-40) = 76.88
W/m
2
µf = 0.0494 lb/hr-ft 3 ρf = 0.0643 lb/ft Kf = 0.00898 w/ft
0.52 28.14⋅1.029⋅.6096 qc1=1.01+0.0372 −5 2 . 04 ⋅ 10
.0295 ⋅ (100-40) = 82.295
100 + 40
= 70o C (Table 1u) (Table 1u) (Table 1u)
1.108⋅0.643 ⋅ 7200 0.0494
q c11.01 0.371
.00898 (100-40) = 25.052
0 .6
W/ft
1.108⋅0.0643⋅7200 0.0494
q c 2 = 0.1695⋅
.00898 ⋅ (100-40) = 23.464
0.52
0.6
W/ft
As instructed in Section 2.4.3, select the larger of the two calculated convection heat losses. qc = 82.295
W/m
qc = 25.052
W/ft
Since the wind is perpendicular to the axis of the conductor, the wind direction multiplier, Kangle, is 1.0, and the forced convection heat loss is greater than the natural convection heat loss. Therefore, the forced convection heat loss will be used in the calculation of thermal rating. Notice that if the wind had been nearly parallel to the line at 10o from the line direction, the wind direction multiplier would be 0.517
4-8
Solar Heating Overhead conductors are typically 5oC to 10oC above air temperature due to solar heating alone, even if the current in the conductor is zero. The conductor heat balance described in these notes applies when there is only solar heat input as well as when the conductor carries electrical current. The solar heat into the conductor in direct sun is a function of the solar heat flux density, the angle of the solar beam relative to the line direction, and the conductor absorptivity (the fraction of incident solar radiation absorbed by the conductor). The resulting temperature rise above air temperature is a function of the conductor emissivity and diameter as well as the wind speed and direction. According to the IEEE or DYNAMP solar models, the maximum conductor rise above air temperature is on the order of 15oC which corresponds to still air. Altitude of the Sun The solar altitude of the sun, Hc, in degrees (or radians) is given by the following equation where inverse trigonometric function arguments are in degrees (or radians): H c = arcsin[cos( Lat )⋅cos(δ )⋅cos(ω ) +sin (Lat )⋅sin (δ )] The hour angle, ω, is the number of hours from noon times 15 degrees (11AM is -15o, at 2PM is +30o). The solar declination, δ, is;
(284+ N ) 360 δ = 23.4583⋅sin 365 where the argument of the sun is in degrees. The equation is valid for all latitudes whether positive (northern hemisphere) or negative (southern hemisphere). For example, consider a line with Drake ACSR that runs East-West at 30o North latitude on June 10 at 11:00AM. In this example: For June 10, the day of the year is: N = 31 + 28 + 31 + 30 + 31 + 10 = 161
The solar declination for June 10 is given:
4-9
284+161 δ = 23.4583 ⋅ sin ⋅360 365
δ = 23.4583 ⋅ 0.981 = 23.02 deg The solar altitude, HC, is found by on the basis of the solar declination of 23o, and the solar latitude of 30 degrees: H C = arcsin[cos(30) ⋅ cos(23.0) ⋅ cos(−15) + sin(30) ⋅ sin( 23.0)] H C = arcsin[0.866 ⋅ 0.920 ⋅ 0.966 + 0.500 ⋅ 0.391 = 74.8 deg
In a somewhat involved calculation using the latitude of the line and the time of day, the solar azimuth of the conductor is found to be 114o. Combining the solar declination and the solar azimuth with the line direction, the combined whole solar angle is 76o and the solar heat input is:
θ = arccos[cos(75) ⋅ cos(114 − 90)] = 76.3 deg qC = 0.5 ⋅ 1027 ⋅ sin(76.3) ⋅ 0.0281 = 14.0 qC = 0.5 ⋅ 95.4 ⋅ sin(76.3) ⋅ 0.092 = 4.26
W/m W/ft
Azimuth of the Sun The solar azimuth, Zc, (in degrees) is: _
Z c =C + arctan (χ ) where
χ=
sin (ω ) sin ( Lat )⋅cos(ω )−cos( Lat )⋅tan (δ )
The solar azimuth constant, C, (in degrees) , is a function of the “Hour angle”, ω, and the solar azimuth variable, χ, as shown in the following table:
4-10
Table 4-3 Solar Azimuth Constant, C, as a Function of “Hour Angle,”,ω ω, and Solar Azimuth Variable,χ χ. “Hour angle”,ω ω,degrees
Cif χ≥0degrees
Cif χ<0degrees
-180≤ω<0()
0
180
0≤ω<180()
180
360
Table 4-4 Altitude, Hc, and Azimuth, Zc, in Degrees of the Sun at Various Latitudes for an Annual Peak Solar Heat Input Degrees North Latitude
Latitude
Local Sun Time
10:00am
Noon
2:00PM
-80
Hc 32
Zc 33
Hc 33
Zc 180
Hc 32
Zc 327
350
-70
40
37
43
180
40
323
350
-60
48
43
53
180
48
317
350
-50
55
52
63
180
55
308
350
-40
60
66
73
180
60
294
350
-30
62
83
83
180
62
277
350
-20
62
96
90
180
62
264
20
-10
61
97
88
180
61
263
50
0
60
91
90
180
60
269
80
+10
61
85
89
180
61
275
110
+20
62
85
90
180
62
275
140
+30
62
97
83
180
62
263
170
+40
60
114
73
180
60
245
170
+50
55
128
63
180
55
232
170
+60
48
137
53
180
48
223
170
+70
40
143
43
180
40
217
170
+80
32
147
33
180
32
213
170
4-11
N
Table 4-5 Total Heat Flux Received by a Surface at Sea Level Normal to the Sun’s Rays Solar Altitude, Hc
QS for a Clear Atmosphere 2
2
QS for an Industrial Atmosphere 2
2
Degrees
(w/m )
(w/ft )
(w/m )
(w/ft )
5
234
21.7
136
12.6
10
433
40.2
240
22.3
15
583
54.2
328
30.5
20
693
64.4
422
39.2
25
770
71.5
502
46.6
30
829
77.0
571
53.0
35
877
81.5
619
57.5
40
913
84.8
662
61.5
45
941
87.4
694
64.5
50
969
90.0
727
67.5
60
1000
92.9
771
71.6
70
1020
95.0
809
75.2
80
1030
95.8
833
77.4
90
1040
96.4
849
78.9
The heat flux density received by a surface at sea level as shown in Table 4-5 may be represented by the following regression equation. Y X
= =
2
total heat flux, QS (w/ft ) solar altitude. HC (degrees)
Q S = A + B H C + C H C2 D H C3 + E H C4 + F H C5 + G H C6
4-12
Table 4-6 Elevation Correction Factor SI
US
A
-42.2391
-3.9241
B
63.8044
5.9276
C
-1.9220
-1.7856×10-1
D
3.46921×10-2
3.223×10-3
E
-3.61118×10-4
-3.3549×10-5
F
1.94318×10-6
1.8053×10-7
G
-4.07608×10-9
-3.7868×10-10
A
53.1821
4.9408
B
14.2110
1.3202
C
6.6138×10-1
6.1444×10-2
D
-3.1658×10-2
-2.9411×10-3
E
+5.4654×10-4
5.07752×10-5
F
-4.3446×10-6
-4.03627×10-7
G
+1.3236×10
Clear Atmosphere
Industrial Atmosphere
-8
where: K solar = A + B⋅H e + C ⋅ H e2 SI
US 1
A
=
1
B
=
1.148×10
C
=
-1.108×10
-4
-8
-5
3.500×10
-9
-1.000×10
4-13
-9
1.22967×10
Table 4-7 Solar Heat Multiplying Factors, Ksolar for High Altitudes Elevation above sea level He - m
Multiplier for values in Table 3
Elevation above sea level He – ft
Multiplier for values in Table 3
0
1.00
0
1.00
1 000
1.10
5 000
1.15
2 000
1.19
10 000
1.25
4 000
1.28
15 000
1.30
Ohmic Losses Conductor resistance per unit length and the electrical current on the line determine the Ohmic losses. The resistance of a stranded conductor is a function of the conductivity of the component wires, the frequency, the current density, the temperature of the wires, and the stranded construction. Some useful rules of thumb are: •
The dc resistance of a single wire is equal to the resistivity of the metal divided by its cross sectional area.
•
The dc resistance of a helical stranded conductor is about 2% more than the parallel combination of component wires.
•
“Skin effect” (an electromagnetic phenomenon wherein the current tends to prefer flowing in the outer layers) is negligible for 1-inch ( 2.54 cm) diameter conductors and causes an increase of about 10% in the resistance of transmission conductors whose outer diameter is between 1.5 and 2.0 inches (3.8 to 5.1 cm).
•
The resistivity of aluminum and copper increases about 4% per 10oC.
•
The conductivity of the steel core of ACSR decreases the resistance by about 2%.
In rating calculations, the change is resistance with temperature is important and must be considered. Neglecting it can cause an error of 10% or more in the rating.
Thermal Rating – Dependence on Location and Orientation Certain geographical parameters can affect line ratings though most are of secondary importance. The major factors related to geographical location are: •
Latitude
•
Elevation above sea level
•
Line direction
•
Industrial versus clear air
4-14
Latitude and line directions are reflected in solar heating of the conductor. Elevation affects both solar heating (which increases with elevation) and heat convection (since the air density and thus the convection heat loss decreases with elevation). Consider the following example: Table 4-8 Thermal Rating for 795 kcmil, 26/7 "Drake" ACSR at 100C with 40C Air Temperature, Emissivity = Absorptivity = 0.5, 2 ft/sec Crosswind, and Direct Sun at 2PM on June 10.
Latitude
Elevation
Line Direction
Air Clarity
Thermal Rating
Deg
Ft (m)
Deg CW from N
Industrial or Clear
Amperes
40
0
90 (east-west)
Clear
996
30
0
90 (east-west)
Clear
996
40
5000 (1524)
90 (east-west)
Clear
946 (-5.0%)
40
0
0 (north-south)
Clear
990 (-0.6%)
40
0
90 (east-west)
Industrial
1011 (+1.5%)
The line direction has a larger effect on solar heating in the early morning and late afternoon but this is primarily of interest in dynamic ratings rather than traditional static rating calculations. In the high elevation case, the reduction in thermal rating is the combined result of a 15% increase in solar heating and a 9% reduction in convective cooling. The presence of an industrial atmosphere is assumed to reduce the solar heating of the conductor by 23%. The engineer can alter none of these rating factors. They are simply characteristics of the line orientation and location. Luckily, none of these factors has a major impact on the line rating. Thermal Rating – Dependence on Conductor Parameters The rating of bare overhead conductors depends on the various conductor parameters including: •
Outside diameter
•
Emissivity & absorptivity
•
Electrical resistance per unit length
At the time of construction, the choice of conductor type and size defines the resistance and outside diameter. Normally, the emissivity and absorptivity are initially in the range of 0.2 to 0.3 4-15
but increase to values close to 1.0 as the conductor ages. Figure 4 shows this increase in emissivity with time for energized conductors. The actual rate at which the conductor emissivity and absorptivity increase with time is a function of the line voltage and the density of particulates in the air. Two observations, however, can be made. The emissivity and absorptivity are correlated so it is unlikely that one parameter will be high and the other low. Also, new conductors will have emissivity and absorptivity values in the range of 0.2 to 0.3 and old conductors will have values in excess of 0.5.
Figure 4-1 Transmission Line Conductor Emissivity as a Function of Time.
As stated above, resistance and diameter are tightly correlated. Thus aluminum, stranded conductors of a given diameter will have a corresponding resistance per unit length. The exceptions to this are: •
The component strands have a different conductivity from that of standard aluminum (e.g. Copper).
•
Conducting strands are trapezoidal rather than round (e.g. TW conductor).
•
The steel core strands are not used or are replaced by Aluminum-clad steel wires (e.g. ACSR/AW).
4-16
Table 4-9 Illustration of the Effect of Diameter,Resistance, and Emissivity & Absorptivity onThermal Rating.
Conductor Description
Outside
Resistance
Emissivity & Absorptivity
Thermal Rating
Diameter
@ 25 °C
inches
Ohms/mi
Drake
1.108
0.1170
0.5 & 0.5
996
Drake/TW
1.010
0.1170
0.5 & 0.5
976 (-2.0%)
Drake/AW
1.108
0.1129
0.5 & 0.5
1014 (+1.8%)
Arbutus AAC
1.026
0.1200
0.5 & 0.5
962 (-3.4%)
CU 500kcmil
0.811
0.1196
0.5 & 0.5
909 (-8.7%)
Drake
1.108
0.1170
0.9 & 0.9
1046 (+5.0%)
Drake
1.108
0.1170
0.3 & 0.3
971 (-2.5%)
Amperes
Thermal Ratings – Dependence on Weather Conditions It is clear from the preceding discussion that the thermal rating of an overhead line is dependent on the weather conditions along it as well as on the type of conductor, its maximum allowable operating temperature. Many utilities around the world adjust their line ratings for seasonal variation in air temperature, recognizing that air temperature is lower and ratings can be higher in the winter than in the summer. Of course in areas where the seasonal change is small (near the equator) or where the fluctuations in any season are larger than the seasonal average difference, this does not make sense. Other utilities adjust thermal ratings for day and night by including or ignoring solar heating, and others adjust the wind speed, using a more conservative (lower) wind speed for continuous ratings than for emergency ratings, which tend to have a low probability of occurrence. Many utilities have installed real-time monitoring systems, adjusting their line ratings for actual real-time wind speed, wind direction, solar heating, and air temperature. This technique of dynamic line rating is discussed in more detail in Chapter 8. In order to illustrate the effect of changing weather conditions on ratings, consider the data shown in Table 4-10:
4-17
Table 4-10 Effect of Weather Conditions on Thermal Ratings. In all Cases, the Conductor is 26/7 795 kcmil ACSR (Drake) with Emissivity = Absorptivity = 0.5, Direct Sun on June 10, Clear Air, at Sea Level, Latitude = 40 Deg, with the Conductor at 100 °C.
Air Temperature
Wind Speed
Deg C
Ft/sec
Wind Direction Relative to the line
Time of day
Thermal Rating Amperes
90 = Perpendicular 40
2
90
2PM
996
40
2
90
12PM
986 (-0.8%)
40
2
90
6PM
1045 (+4.9%
30
2
90
2PM
1081 (+8.5%)
40
0
90
2PM
838 (-15.6%)
40
3
90
2PM
1183 (+18.7%)
40
6
10
2PM
968 (-2.8%)
By reviewing this limited series of rating calculations, a number of important aspects of line rating dependence on weather can be drawn: •
Rating variation due to solar heating changes throughout the day is less than 5%.
•
Air temperature variation is important. A difference of 10 oC in air temperature causes a line rating change of nearly 10%.
•
Relatively small differences in wind speed, in the range of 0 to 3 ft/sec (0.91 m/sec) can make a big difference in the line rating, generally 10% to 20%.
•
The wind direction relative to the line is as important as the speed. A 6 ft/sec (1.8 m/sec) wind blowing near parallel to the line (10 deg) yields a slightly lower line rating than a 2 ft/sec (0.61 m/sec) wind blowing perpendicular to the line.
Thermal Ratings – Dependence on Maximum Allowable Conductor Temperature (MACT) Until the early 1970’s, the National Electric Safety Code suggested that minimum electrical clearances were to be met at conductor temperatures up to 120oF (49oC). Line thermal capacity
4-18
was typically calculated by conductor manufacturers for a conductor temperature of 75oC, a temperature sure to avoid possible annealing problems with aluminum and copper. In the 1970’s, the NESC changed and stated that the electrical clearances listed were to be met at “The maximum conductor temperature for which the line was designed to operate, if greater than 50oC, with no wind displacement” (excerpted from Rule 232.A.2). Thus the maximum allowable conductor temperature (MACT) used in line rating calculations may vary from 50oC to 200oC according to available ground clearance and consistent with concerns about loss of tensile strength at temperatures above 90oC. Consider the following table of line ratings as a function of the maximum allowable conductor temperature Table 4-11 Line Thermal Rating as a Function of Maximum Allowable Conductor Temperature. In all Cases, the Conductor is 26/7 795kcmil ACSR (Drake) with Emissivity=Absorptivity=0.5, Direct Sun on June 10, Clear Air, at Sea Level, Latitude=40deg, with Line Oriented East-West Maximum Allowable Conductor Temperature
Air Temperature
Perpendicular
Sun?
Thermal Rating
Deg C
Deg C
ft/sec
m/sec
100
40
2
0.61
Yes
996
75
40
2
0.61
Yes
742 (-25.0%)
75
30
2
0.61
Yes
861 {+16%}
75
40
3
0.91
Yes
823 {+11%}
75
40
2
0.61
No
833 {+12%}
125
40
2
0.61
Yes
1182 (+18.7%)
125
30
2
0.61
Yes
1249 {+5.7%}
125
40
3
0.91
Yes
1287 {+8.9%}
125
40
2
0.61
No
1232 {+4.2%}
Wind Speed Amperes
In Table 4-11, Line Thermal Rating as a Function of Maximum Allowable Conductor Temperature. In all Cases, the Conductor is 26/7 795kcmil ACSR (Drake) with Emissivity=Absorptivity=0.5, Direct Sun on June 10, Clear Air, at Sea Level, Latitude=40deg, with Line Oriented East-West, the shaded rows can be compared to determine the effect of maximum allowable conductor temperature (MACT) on line rating. Increasing the MACT from 75oC to 100oC causes a corresponding line rating increase from 782 to 996 Amperes, or 25%. A further increase to 125oC causes the line rating to go to 1182 Amperes, which is an increase of 18.7%. If a change of 25oC in the MACT causes the same change in high temperature sag, then physical modifications to raise attachment points or re-tension the line would be more effective on existing lines with relatively low MACTs.
4-19
Considering the non-shaded rows in Table 4-11, it can be seen that the incremental changes (shown in the {} brackets) in line rating for changes in weather conditions are generally much less at a MACT of 125oC than at 75oC. This is particularly true for changes in air temperature and solar heating. Thus, simple ambient-adjusted dynamic rating or static re-rating methods are less effective on lines with a high MACT. The impact of wind is, however, relatively independent of MACT and dynamic rating or static re-rating methods, which consider variations in wind speed and direction are nearly as effective at high as at low MACTs.
4-20
5 CONSEQUENCES OF TRANSMISSION LINE OPERATION AT HIGH TEMPERATURE Conductor Material Properties Materials commonly used in conductors are aluminum, copper, and steel. A Summary of the properties of these common materials fabricated as wires is in Table 5-1a and 5-1b. Galvanized steel wires are combined with aluminum in the most common type of overhead conductor -Aluminum Conductor Steel Reinforced (ACSR). The use of copper is uncommon in modern transmission lines since it weighs and usually costs considerably more than aluminum conductor of the same resistance. With one or more wires combined into a stranded overhead conductor, the conductor is held in the air at each structure connected to an insulating arm by means of a clamp. At high electrical load levels, the conductor temperature and therefore its sag increases. The sag of the conductor at high temperatures and the minimum safe ground clearance usually determines the structure height. The loading of the structure is determined by the weight of its iced conductors, the transverse wind load on the conductors attached to it, and, for angle and dead-end structures, by the maximum tension attained by the conductors. Conductor sag behavior at its maximum temperature and its tension and weight under ice and wind load thus determines both the structure height and the minimum required structure/foundation load capability.
Conductor Design & Construction "Standard" bare overhead conductors consist of round strands helically laid about a core in one or more layers. In a homogeneous conductor - all aluminum conductors (AAC), hard drawn copper conductors (CU), or all aluminum alloy conductors (AAAC5005 or AAAC6201) - the core consists of a single strand identical to the outer strands. Since all the strands are the same diameter, one can show that the innermost layer always consists of 6 strands, the second layer of 12 strands, etc., making conductors having 1, 7, 19, 37, 61, 91, or 128 strands. In a non-homogeneous conductor - aluminum conductor steel reinforced (ACSR), aluminum conductor alumoweld steel reinforced (ACSR/AW), or hard drawn copper conductor copperweld steel reinforced (CU/CW), or aluminum conductor aluminum alloy reinforced - the strands in the core may or may not be of the same diameter. In a 30/7 ACSR conductor the aluminum and steel strands are of the same diameter. In a 30/19 ACSR they are not. Within the core or within 5-1
the outer layers, however, the number of strands always increases by a sixth of an inch in each succeeding layer. Thus, in 26/7 ACSR, the number of layers in the inner layer of aluminum is 10 and in the outer layer 16. Table 5-1a Basic Material Properties of Wire Used in Overhead Conductor International Annealed Copper Standard
Commercial Hard-Drawn Copper Wire
Standard 1350-H19 Aluminum Wire
100.00
96.2
61.2
0.008145
0.0083974
0.013310
17.24
17.774
28.173
1.00
1.03
0.50
0.00218
0.00212
0.00224
Temp. coefficient of resistance per C at 20 C
0.00393
0.00381*
0.00403
Density at 20 oC, lb/in3
0.32117
0.321
0.09765
8.89
8.89
2.703
Coefficient of Linear Expansion per F
0.0000094
0.0000094
0.0000128
Coefficient of Linear Expansion per oC
0.0000169
PROPERTY
Conductivity, Percent IACS at 20oC (68°F) Resistivity at 20oC,Α-in2/1000ft Resistivity at 20oC,Α-mm2/km Ratio of weight for equal D-C resistance and length Temp. coefficient of resistance per oF o
o
Density at 20 oC, g/cm3 o
0.0000230
Modulus of Elasticity Solid Wire Approximate, Mpsi
---
17
10
Modulus of Elasticity Solid Wire Approximate, MPa
---
117,000
69,000
0.0921
0.0921
0.214
Tensile Strength, ksi
62.0
62.0
24.0
Tensile Strength, MPa
430
430
165
Minimum Elongation, %
1.1
1.1
1.5
Specific Heat cal/gm/oC (at 20oC)
The cross sectional area of aluminum or copper is typically measured in kcmil or square millimeters. The symbol “kcmil” is shorthand for thousands of circular mils. A strand that is 0.1 inches in diameter (100 mils), has a circular mil area of 10 kcmil. The approximate cross sectional area in square millimeters may be obtained by dividing the kcmil area by 2. The smallest sizes of conductor are usually described in terms of wire gauge. The wire gauge numbers correspond to certain kcmil areas of aluminum. A #4/0 AWG ACSR conductor has 236 kcmil of aluminum.
5-2
Table 5-1b Basic Material Properties of Wire Used in Overhead Conductor Standard 6201T81 Aluminum Wire
Galvanized Steel Core Wire
Aluminum CladSteel (Alumoweld)
52.5
8.0
20.3
0.015515
0.10182
0.04007
32.840
215.52
84.815
0.58
10.6
3.54
Temp. coefficient of resistance per F
0.00193
0.00178
0.00200
Temp. coefficient of resistance per oC at 20oC
0.00347
0.00320
0.00360
Density at 20 oC, lb/in3
0.09765
0.281
0.2381
2.703
7.78
6.590
0.0000128
0.0000064
0.0000072
0.0000230
0.0000115
0.0000130
Modulus of Elasticity Solid Wire Approximate, Mpsi
10
29
23.5
Modulus of Elasticity Solid Wire Approximate, MPa
69,000
200,000
162,000
0.214
0.107
0.112
Tensile Strength, ksi
46.0
185
175
Tensile Strength, MPa
320
1280
1210
Minimum Elongation, %
3.0
3.5
1.5
PROPERTY Conductivity, Percent IACS at 20oC (68°F) Resistivity at 20oC,Α-in2/1000ft Resistivity at 20oC,Α-mm2/km Ratio of weight for equal D-C resistance and length o
o
3
Density at 20 C, g/cm
Coefficient of Linear Expansion per oF o
Coefficient of Linear Expansion per C
o
o
Specific Heat cal/gm/ C (at 20 C)
The most common type of transmission conductor is ACSR. ACSR consists of one or more layers of aluminum strands surrounding a core of 1, 7, 19, or 37 galvanized steel strands. ACSR is manufactured in a wide range of sizes and strandings ranging from #6 AWG 6/1 (OD = 0.198 inches [5.1 mm]) to 2156 kcmil, 84/19 “Bluebird” (OD = 1.762 inches [45.5 mm]). Certain strandings are stronger than others. 36/1 ACSR is the weakest stranding (1/37 of the cross sectional area is steel). 30/7 is the strongest (7/37 of the cross section is steel). The following tables group strandings of ACSR by strength according to a "Type No." classification where the Type No. is the percentage ratio of steel to aluminum cross sectional areas. Consider the following 795 kcmil (400 mm2) conductors listed in order of increasing rated breaking strength:
5-3
Table 5-2 Comparison of Mechanical Properties for Different Strandings of 795 kcmil ACSR Conductors (US Common Units). Type No.
Code Name
Alum Wire No. x OD
Steel Wire No. x OD
Overall Diameter
Rated Strength
Total Weight
Core Weight
(in)
(in)
(in)
(lbs)
(lbs/ft)
(lbs/ft)
0
Arbutus
37x0.1466
None
1.026
13,900
746×103
0
3
Coot
36x0.1488
1x0.1488
1.040
16,800
805×103
59×103
7
Turbot
20x0.1994
7x0.0886
1.063
21,800
896×103
150×103
10
Puffin
22x0.1901
7x0.1056
1.077
24,800
958×103
212×103
16
Drake
26x0.1749
7x0.1360
1.108
31,500
1094×103
344×103
23
Skimmer
30x0.1628
7x0.1628
1.140
38,300
1246×103
483×103
Table 5-3 2 Comparison of Mechanical Properties for Different Strandings of 400mm ACSR Conductors (SI Units). Type No.
Code Name
Alum Wire No. x OD
Steel Wire No. x OD
Overall Diameter
Rated Strength
Total Weight
Core Weight
(mm)
(mm)
(mm)
(N)
(N/km)
(N/km)
0
Arbutus
37x3.724
None
26.1
61800
10890
0
3
Coot
36x3.780
1x3.780
26.4
74700
11750
860
7
Turbot
20x5.065
7x2.250
27.0
97000
13080
2190
10
Puffin
22x4.829
7x2.682
27.4
110300
13980
3090
16
Drake
26x4.442
7x3.454
28.1
140100
15960
5020
23
Skimmer
30x4.135
7x4.135
29.0
170400
18180
7050
The stronger the ACSR conductor is, the higher the conductor tension under all conditions, and the less the conductor stretches under load (thus reducing sag increase for a given ice and wind loading). High strength strandings of ACSR also exhibit less thermal elongation and less high temperature creep so it is likely that the sag increase under high temperature conditions will be less. The major drawbacks to high strength ACSR are cost (a 30/7 ACSR conductor costs about 30% more than an all aluminum conductor of the same kcmil area), increased angle structure tension loads, and, under certain conditions, increased aeolian vibration induced fatigue of the aluminum strands.
5-4
Non-Standard Conductors In addition to considering different sizes and strandings of standard conductors, the line designer may also want to consider the use of a number of non-standard conductors if their special properties offer sufficient advantage in a particular line design situation. The main types of special conductors include “self-damping conductor” (SDC), “aluminum conductor steel supported” (ACSS), “trapezoidal wire conductor” (TW - a conductor having aluminum strands with a trapezoidal shape rather than round), or “T2” (also called “VR” for variable ratio) conductor consisting of two sub conductors twisted about one another with a lay length of about 3 meters. The value of the use of such special conductors may be economic or they may offer increased reliability or offer a unique solution to an otherwise impossible design problem. It is difficult to assess the value of special conductors without the use of advanced line design techniques. With such techniques available, however, one can consider the value of the following items: •
Lower electrical resistance for the same conductor diameter [TW] yielding lower electrical losses with the same wind and ice structure loads.
•
Lower thermal elongation [ACSS] yielding less increase in sag at high temperatures.
•
Higher annealing temperatures [ACSS] yielding increased thermal rating.
•
Reduced Aeolian vibration activity [SDC, ACSS, T2] allowing new lines to be strung with less sag for the same Aeolian vibration amplitude or with the same sag and lower Aeolian vibration.
SDC - "Self-damping Conductor" Manufactured with a conventional stranded steel core, this conductor’s innermost layers of aluminum (and usually the outer layers) consist of trapezoidal strands sized such that a gap exists between the steel core and the innermost layer, even with the conductor under full tension. Under vibration, the steel core and the aluminum layers vibrate with different frequencies and impact damping results. This impact damping is sufficient to keep any Aeolian vibration to a low level. The use of trapezoidal strands also results in reduced conductor diameter for a given AC resistance per mile [km]. The major advantages are: •
High self-damping allows the use of higher unloaded tension levels resulting in reduced maximum sag and thus reduced structure height and/or fewer structures per mile [km].
•
Reduced diameter for a given AC resistance yields reduced structure transverse wind and ice loading.
The major disadvantages are: •
There may be increased installation and clipping costs.
•
The conductor design always requires the use of a steel core even in light loading areas.
5-5
TW – “Trapezoidal Wire” This conductor is essentially similar to SDC conductor except that there is no gap between the layers. TW may also be manufactured without a steel core. It has none of SDC's self-damping properties but it presents a diameter, which is approximately 10% less than a standard ACSR conductor of the same AC resistance whereas SDC is only 5% less. Table 5-4 Comparison of AAC with AAC/TW Alternatives DC Resistance @ 20°°C
Diameter
Conductor Description (in)
(mm)
(%)
(A/1000ft)
(A/1000m)
(%)
Arbutus AAC
1.026
26.1
100
0.0217
0.0712
100
Arbutus/TW
0.919
23.3
89.5
0.0217
0.0712
100
Rainier/TW
1.00
25.4
97.4
0.0188
0.0617
86.6
T2 - "Twisted 2 Conductor" The conductor consists of two standard conductors twisted about one another with a twist length of approximately 3 meters. The conductor cross section is a rotating "figure-8". The sub conductors can be any of the standard conductors. The major advantages are: •
Reduction or elimination of the amplitude and frequency of occurrence of large amplitude "ice-galloping" motions. .
•
The non-round shape of this conductor reduces the amplitude of aeolian vibration and the accompanying fatigue inducing strains near clamps. Consequently, T2 conductor can be installed to higher tension levels and reduced sags.
The major disadvantages are: •
The non-round cross section yields wind and ice loadings that are about 11% higher than standard conductor of the same AC resistance per mile.
•
The installation of, and hardware for this conductor, can be somewhat more expensive than the cost of standard conductor.
ACSS - "Aluminum Conductor Steel Supported" This conductor appears to be similar to standard ACSR except for the fully annealed aluminum strands. Annealing the aluminum strands reduces the composite conductor strength but, after installation, permanent elongation of the aluminum strands results in a much larger percentage of the conductor tension being carried in the steel core than is true for standard ACSR. This in turn yields reduced composite thermal elongation and increased self-damping. The major advantages of ACSS are as follows:
5-6
•
Since the aluminum strands are "dead-soft" to begin with, the conductor may be operated at temperatures in excess of 200°C without loss of strength.
•
Since the tension in the aluminum strands is normally low, the conductor's selfdamping of Aeolian vibration is high and it may be installed at high unloaded tension levels without the need for separate Stockbridge dampers.
The major disadvantages of ACSS are: •
In areas experiencing heavy ice load, the reduced strength of this conductor relative to standard ACSR may make it less desirable.
•
The softness of the annealed aluminum strands and the possible need for pre-stressing prior to clipping and sagging may raise installation costs.
Stress-Strain Characteristics Stress-strain curves for bare overhead conductors include a minimum of an initial curve and a final curve ranging from 0 to 0.45%. For conductors consisting of two materials, an initial and final curve for each is included. Creep curves for various lengths of time are typically included. Overhead conductors are not purely elastic. They stretch with tension, but when the tension is reduced to zero, they do not return to their initial length. That is, conductors are plastic; the change in conductor length cannot be expressed with a simple linear equation, as used in the preceding hand calculations. The permanent length increase that occurs in overhead conductors yields the difference in initial and final sag-tension data found in most computer programs. Figure 5-1 shows a typical stress-strain curve[5] for a 26/7 ACSR conductor; the curve is valid for conductor sizes ranging from 266.8 to 795 kcmil. A 795 kcmil-26/7 ACSR (Drake) conductor has a breaking strength of 31,500 lbs. [14,000 kg.] and an area of 0.7264 in2 [46.9 MM.] so that it fails at an average stress of 43,000 psi [30 kgs/mm2]. The stress-strain curve illustrates that at a stress equal to 50% of the conductor’s breaking strength (21,500 psi), the elongation is less than 0.3%. This translates to an elongation of 1.8 feet [0.55 m] in a 600-ft [180-m] span. Note that the component curves for the steel core and the aluminum stranded outer layers are separated. This separation allows for changes in the relative curve locations as the temperature of the conductor changes. For the preceding example, with the Drake conductor at a tension of 6300 lb [2860 kg], the length of the conductor in the 600-ft [180-m] span was found to be 0.27 ft longer than the span. This tension corresponds to a stress of 8600 psi (6.05 kg/mm2). From the stress-strain curve in Figure 5-1, this corresponds to an initial elongation of 0.105% (0.63 ft). As in the preceding hand calculation, if the conductor is reduced to zero tension, its unstressed length would be less than the span length. Figure 5-2 is a stress-strain curve[5] for an all aluminum 37-strand conductor ranging in size from 250 kcmil to 1033.5 kcmil. Because the conductor is made entirely of aluminum, there is only one initial and final curve.
5-7
Figure 5-1 Stress-Strain Curve for ACSR Conductor.
5-8
Figure 5-2 Stress-Strain Curve for All Aluminum Conductor
Creep Elongation Once a conductor has been installed to an initial tension, it can elongate further. Such elongation results from two phenomena, permanent elongation due to high-tension levels resulting from ice and wind loads and creep elongation under everyday tension levels. These types of conductor elongation are discussed in the following sections.
5-9
Creep Due to Heavy Loading When an aluminum-stranded conductor is initially installed, it elongates non-linearly. If the conductor tension increases to a relatively high level under ice and wind loading, the conductor will elongate. When the wind and ice loads abate, the conductor elongation will reduce along a curve parallel to the final curve, but will never return to its original length. For example, refer to Figure 5-2 and assume that a newly strung 795-kcmil, 37-strand AAC (Arbutus) conductor has an everyday tension of 2780 lbs. The conductor area is 0.6245 in2, so the everyday stress is 4,450 psi and the elongation is 0.062%. Following an extremely heavy ice and wind load event, assume that the conductor stress reaches 18000 psi. When the conductor tension decreases back to everyday levels, the conductor elongation will be permanently increased by more than 0.2%. In addition, the sag under everyday conditions will be correspondingly greater, and the tension will be less. In most numerical sag-tension methods, final sag-tensions are calculated for such permanent elongation due to heavy loading conditions. The definition of “normal” creep is the accumulative non-elastic elongation of a conductor under tension, over an extended period of time at modest temperatures usually not in excess of approximately 75°C.A conductor under tension undergoes non-elastic elongation over a period of time (usually measured in years). This elongation is creep. The magnitude and rate of creep are a function of the conductor's composition, stranding, line tension, and operating temperature. Conductors exhibit creep under everyday tension levels even if the tension level never exceeds normal levels. Creep can be determined by long-term laboratory creep tests. The results of the tests are used to generate creep versus time curves. On the stress-strain graphs, creep curves are often shown for 6-month, 1-year, and 10-year periods. Figure shows these typical creep curves for a 37-strand 250 kcmil through 1033.5 kcmil AAC. In Figure , assume that the conductor tension remains constant at the initial stress of 4,450 psi. At the intersection of this stress level and the initial elongation curve, 6-month, 1-year, and 10-year creep curves, the conductor elongation from the initial elongation of 0.062% increases to 0.11%, 0.12%, and 0.15%, respectively. Because of creep elongation, the resulting final sags are greater and the conductor tension is less than the initial values. Creep elongation in aluminum conductors is quite predictable as a function of time and obeys a simple exponential relationship. Thus, the permanent elongation due to creep at everyday tension can be found for any period of time after initial installation. Creep elongation of copper and steel strands is much less and is normally ignored. Permanent increase in conductor length due to heavy load occurrences cannot be predicted at the time a line is built. The reason for this unpredictability is the random nature of heavy ice and wind loads. A heavy ice storm may occur the day after the line is built or may never occur over the life of the line.
Annealing of Aluminum The American Society for Testing and Materials (ASTM) or the International Engineering Consortium (IEC) standards specify the minimum tensile strength of aluminum and copper wires, which is the stress at which the wire breaks. At temperatures above 75°C, the tensile
5-10
strength decreases with time. Temperatures below 300°C do not affect the tensile strength of galvanized, aluminum-clad, or copper-clad steel wires. Thus, extended exposure of conductors made up largely of aluminum or copper wires to temperatures above 75oC can eventually lead to tensile failures during high ice and/or wind loading events. Figure 5-3 shows the reduction in tensile strength with time and temperature for a sample of 0.081 inch (0.2 cm) diameter hard drawn copper wire. There are 8760 hours in a year, so the diagram clearly shows that sustained operation at 65oC yields no measurable reduction of tensile strength, sustained operation at 100oC yields a 10% reduction in 600 hours (25 days), and that only 40 hours at 125oC reduces the wire tensile strength by 10%.
Figure 5-3 Annealing of 0.081 Inch Diameter Hard Drawn Copper Wire
Figure 5-4 shows similar tensile strength reduction data for 1350-H19 “EC” hard drawn aluminum wire. In general, tensile strength reduction of aluminum wires at temperatures of less than 90oC is considered negligible. At 100oC, the tensile strength of the wire is reduced by 10% after 5000 hours and at 125oC, the tensile strength is reduced 10% after 250 hours. When compared to copper, aluminum appears to anneal somewhat more slowly though the difference is probably not important in transmission line applications. The source of the copper wire data also noted a significant amount of variation in the annealing rates for wire obtained from different manufacturers.
5-11
Figure 5-4 Annealing of 1350-H19 Hard Drawn Aluminum Wire
5-12
Residual Strength Predictor Equations for Aluminum Conductors Definition of Terms: RS1350 Residual aluminum (1350 Alloy) strength as a percentage of initial strength [%] RS6201 Residual 6201 Alloy strength as a percentage of initial strength [%] RSCOM Residual strength of composite conductor as a percentage of initial strength [%] T
-
Temperature [°C]
t
-
Elapsed time [hours]
d
-
Strand diameter [mm, in.]
A1350 -
Area of aluminum (1350 Alloy) strands [sq. mm, sq. in.]
A6201 -
Area of 6201 alloy strands [sq. mm, sq. in.]
AT
Total area [sq. mm, sq. in.]
-
STR1350
-
STRST -
Calculated initial strength of the steel core [N, lbs]
STRT
Calculated initial strength of the conductor [N, lbs]
-
Calculated initial strength of the aluminum (1350 Alloy) strands [N, lbs]
Predictor Equations: (Metric) AAC:
RS1350 =
(-0.24 T + 134) t -(0.001 T - 0.095)(2.54/d) (Note: If (-0.24T+134) > 100, use 100 for this term.)
AAAC: RS6201 =
(-0.52 T + 176) t -(0.0012 T - 0.118)(2.54/d) (Note: If (-0.52T+176) > 100, use 100 for this term.)
ACAR: RSCOM =
(RS1350 )(A1350/AT) + (RS6201)(A6201/AT)
ACSR: RSCOM =
(RS1350 )( STR1350 / STRT) + 109(STRST / STRT)
5-13
Predictor Equations: (English) AAC:
RS1350 =
(-0.24 T + 134) t -(0.001 T - 0.095)(0.1/d) (Note: If (-0.24T+134) > 100, use 100 for this term.)
AAAC: RS6201 =
(-0.52 T + 176) t -(0.0012 T - 0.118)(0.1/d) (Note: If (-0.52T+176) > 100, use 100 for this term.)
ACAR: RSCOM =
(RS1350)(A1350/AT) + (RS6201 )(A6201/AT)
ACSR: RSCOM =
(RS1350 )( STR1350 / STRT) + 109(STRST / STRT)
In applying these equations, the cumulative strength reduction for multiple exposures at the same conductor temperature is simply additive, however this is not true for multiple exposures at different conductor temperatures. To determine the cumulative strength reduction for a series of high temperature exposures at different temperatures and times, all exposures must be expressed in equivalent time at the highest temperature before adding. Thus if an all aluminum conductor, consisting of 37-0.1466 inch diameter strands, is raised to 125oC for 100 hours and then at a later time for 50 hours, then the strength reduction can be calculated for 150 hours at 125oC. If the same conductor is raised to 125oC for 100 hours and then at a later time is raised to 150oC for 50 hours, then the following calculation must be performed: For 100 hours @125oC, RS = 100 × 100
0.1 − (0.125 − 0.095 )• 0.1466
= 91.0%
At 150oC, RS = 91.0% after 7.2 hours, so the cumulative loss of strength over the two high temperature exposures is equal to the remaining strength after 50+7.2 hours. It is 82.1%
Thermal Elongation ACSR and AAC conductors elongate with increasing conductor temperature. The rate of linear thermal expansion for the composite ACSR conductor is less than that of the AAC conductor because the steel strands in the ACSR elongate at approximately half the rate of aluminum. The composite coefficient of linear thermal expansion of a non-homogenous conductor, such as “ACSR” Drake, may be found from the following equations: E ∂ AS = ∂ AL AL E AS
AAL ATOTAL
E + ∂ ST ST E AS
AST ATOTAL
5-14
A A E AS = E AL AL + EST ST ATOTAL ATOTAL where EAL
= modulus of elasticity of aluminum, psi
EST
= modulus of elasticity of steel, psi
EAS
= modulus of elasticity of aluminum-steel composite, psi
AAL = area of aluminum strands, square units AST
= area of steel strands, square units
ATOTAL
= total cross sectional area, square units
αAL
= aluminum coefficient of linear thermal expansion, per oF
αST
= steel coefficient of thermal elongation, per oF
αAS
= composite aluminum-steel coefficient of thermal elongation, per oF
Using elastic moduli of 10 and 30 million psi for aluminum and steel, respectively, the elastic modulus for “ACSR” Drake is:
(
)
(
)
0.6247 0.1017 E AS = 10 x10 6 + 30 x10 6 = 12.8 x10 6 psi 0.7264 0.7264 and the coefficient of linear thermal expansion is: 6 0.1017 10 x10 6 0.6247 − 6 30 x10 −6 + a AS = 12.8 x10 −6 6 . 4 x 10 = 10.7 x10 / ° F 6 6 12.8 x10 0.7264 12.8 x10 0.7264 As is discussed in Section 6 of this guide, the high temperature of behavior of ACSR can be considerably more complex and non-linear than is indicated by these simple equations. The complexity and non-linearity come because of the different elastic modulus and thermal elongation coefficients of aluminum and steel and are accentuated in ACSR conductors that have a high percentage of steel. In conductors with 18/1 or 45/7 stranding, the high temperature behavior may essentially be modeled up to 100oC by the simple method described, however, 26/7 and 30/7 ACSR cannot be modeled with this simple method.
The conditions under which calculations using a simple composite modulus and coefficient of thermal elongation fail may be illustrated by considering the tension distribution between steel and aluminum under normal and high temperature conditions. The preceding equations for composite modulus and thermal coefficient of elongation are derived with the assumption that the aluminum and steel strands have the same length when on the reel and after the conductor has been sagged. Under this assumption, the total conductor tension (HAS) is equal to the sum of the component tensions and the elongation of the steel and aluminum must be equal:
5-15
H AS = H AL + H ST H ST H AL = AST ⋅ EST AAL ⋅ E AL For a “Drake” 26/7 ACSR installed in a 600 ft (183 m) span to an initial tension of 9450 lbs (4286 kg), the tension in the steel core is 3124 lbs (1417 kg), or33% of the total tension. If the conductor is heated to a temperature of 212oF (100oC), the sag increases and the total tension decreases to 4780 lbs (2168 kg), but the tension in the steel core goes up to 3305 lbs (1499 kg), or 69% of the total tension. As the temperature increases further, the tension in the aluminum eventually decreases to zero. Beyond that “knee point” temperature, the expansion of the conductor continues, but the aluminum strands are in compression. The “knee point” temperature is lowest for ACSR conductors having the highest percentage of steel and, for any ACSR, is further reduced by creep elongation of the aluminum strands. Thermal expansion at high operating temperatures for ACSRs is discussed in the next chapter. The correct calculation of sag change at high temperature can have a large impact on the proper choice of which uprating method needs to be implemented.
High Temperature Creep Elongation Creep, Accelerated Rate- An increase in a conductor’s creep rate over general creep rate, usually associated with elevated temperature operations. Creep, High Temperature- The creep a conductor experiences over a period of time operating at conductor temperatures in excess of approximately 75°C. Generally, high temperature creep should be considered when conductor temperatures exceed 75°C. Because aluminum has a much higher creep rate than steel, all-aluminum type conductors such as AAC, AAAC & ACAR are much more susceptible to high temperature creep. Conversely, copper and steel supported aluminum conductors (Cu, ACSR, & AACSR), are less affected. Pre-stressed ACSS has its aluminum strands fully annealed and consequently carries negligible mechanical load; hence the steel core, which is generally not affected by creep below 200°C, carries all load. Effect on Sag-Tension At elevated temperatures, conductor sags and tensions are affected by an accelerated creep rate and the thermal expansion of conductor strand materials. Aluminum strands expand at twice the rate of steel strands. The effect of high temperature operations on the sag of all-aluminum conductors is greater than the effect for composite conductors. In a composite conductor, as temperature increases, the conductor tension transfers from the aluminum strands to the steel strands. This load transfer decreases the creep rate on the aluminum, and reduces the elongation of the conductor due to thermal expansion. If the tensile load is completely transferred, or "offloaded" to the steel, only the creep and thermal expansion of the steel strands further effect conductor sag.
5-16
Elevated temperature effect on sags and tensions for conductors with a high steel content are reduced because the aluminum may off-load at relatively low temperatures (greater than 7.5% steel by area). Since the steel has picked up most of the conductor’s mechanical load at relatively low operating temperatures, the aluminum's influence on sags and tensions is minimal. Hence, high steel reinforced conductors are less susceptible to high temperature creep than conductors with lower steel ratios. For modest operating temperatures, ACSS conductors quickly off-load the aluminum strands (especially if pre-stressed). Hence, high temperature effects on sags and tensions for ACSS conductors are smaller than the effects on high steel conductors, and exhibit negligible high temperature creep below 200°C. Creep Predictor Equations Creep Predictor Equations for High Temperature Operations Definition of Terms:
εc ε ΣεT σ α t T ∆T AEC AST AT %RS
- Primary creep strain (units/unit) - Strain - increase in length/original (units/unit) - Increase in conductor strain due to elevated temperature operations (units/unit) -
2
2
Stress - tension/area (N/mm , lbs/in ) Coefficient of thermal expansion (units/unit/°C) Elapsed time (hours) Conductor temperature (°C) Temperature change value (°C) Area of aluminum strands (sq. mm., sq. in.) Area of steel strands (sq. mm., sq. in.) Total conductor area (sq. mm., sq. in.) Tension as a percentage of the rated strength (%)
Formula Constants: (Metric) Table 5-5 Formula Constants (Metric Units) 7 Strands
19 Strands
37 Strands
61 Strands
K1
1.36
1.29
1.23
1.16
K2
0.84
0.77
0.77
0.71
M1
0.0148
0.0142
0.0136
0.0129
M2
0.0090
0.0090
0.0084
0.0077
G
0.71
0.65
0.77
0.61
5-17
Formula Constants: (English) Table 5-6 Formula Constants (English Units) 7 Strands
19 Strands
37 Strands
61 Strands
K3
0.0021
0.0020
0.0019
0.0018
K4
0.0013
0.0012
0.0012
0.0011
M3
0.000023
0.000022
0.000021
0.000020
M4
0.000014
0.000014
0.000013
0.000012
G
0.0011
0.0010
0.0012
0.00094
Note: K1, K3, M1, & M3 are for wire bar rolled rod and K2, K4, M2, & M4 are for continuous cast (rolled) rod.
Predictor Equations: All-Aluminum Conductors Room Temperature: (Metric) AAC:
εc =
K
σ1.3 t 0.16
AAAC:
εc =
G
σ1.3 t 0.16
ACAR:
εc =
(0.19 + 1.36 AEC/ AT) (T
1.4
σ1.3 t 0.16)
Room Temperature: (English) AAC:
εc =
K
σ1.3 t 0.16
AAAC:
εc =
G
σ1.3 t 0.16
ACAR:
εc =
(0.0003 + 0.0021 AEC/ AT) (T
1.4
σ1.3 t 0.16)
Elevated Temperature: (Metric) AAC:
εc =
M T
AAAC:
εc =
0.0077 T
ACAR:
εc =
(0.0019 +0.012 AEC/ AT) (T
1.4
σ1.3 t 0.16 1.4
σ1.3 t 0.16
Elevated Temperature: (English) AAC:
εc =
M T
1.4
σ1.3 t 0.16
5-18
1.4
σ1.3 t 0.16)
AAAC:
εc =
0.000012 T
σ1.3 t 0.16
ACAR:
εc =
(0.000003 +0.000019 AEC/ AT) (T
1.4
1.4
σ1.3 t 0.16)
Steel Reinforced Conductors (ACSR & AACSR) Room Temperature: Aluminum strands drawn from hot-rolled rod:
εc =
2.4 (%RS)
1.3
0.16
t
Aluminum strands drawn from continuous cast rod:
εc =
1.1 (%RS)
1.3
t
0.16
Elevated Temperature: Only for conductors with less than 7.5% steel by area:
εc =
.24 (%RS) T t
0.16
Elevated creep strain for conductors with a steel core equal to or greater than 7.5% steel by area can be ignored.
Temperature Change Value
The temperature change value is a calculated temperature that approximates the net increase in microstrain due to elevated temperature creep over general creep. ΣεT = α ∆T
or
∆T
=
ΣεT/α
where
ΣεT =
ε@high - ε@ambient
ε@ambient is the strain due to room temperature creep only and ε@high is the strain due to elevated (high) temperature creep. Use of Predictor Equations:
• • • • • •
Use standard graphic or computer sag & tension methods to predict the sags and tensions without elevated creep for the given situation. Compute the creep at ambient temperature. Compute the creep at the first elevated temperature. Compute how many hours it would take to get this same amount of creep at the second elevated temperature. Repeat items 3 & 4 for all elevated temperatures. Calculate the temperature change value by subtracting the creep elongation at everyday temperature from the creep elongation at elevated temperature.
5-19
•
Calculate the final sag following elevated temperature creep by adding this temperature change value to the temperatures used in the standard sag & tension calculation. The above creep predictor equations were developed by Harvey and Larson. Note that the creep elongation calculated by these equations is the total creep that includes the initial 1-hour hold elongation at the temperature in question.
Connectors at High Temperature A quality connector design will provide suitable conductance through the connector, low resistance at the contact interfaces, adequate strength for intended mechanical loads, and an appropriate amount of heat radiating surface area. Limited Tension Connectors - Limited tension connectors are primarily designed to join conductors that are under little or no mechanical tension. They are typically used to splice the ends of two conductors together in a low tension application, tap a second conductor from a continuous run conductor, or terminate the end of a conductor in a low tension application. Typical types of limited tension connectors are bolted connectors, compression connectors, formed-wire connectors, wedge type connectors, and implosive connectors. Because of their limited mechanical holding strength, the portion of the connector that is in contact with the conductor is generally less in area than that of its full tension counterpart. Full Tension Connectors - In addition to providing continuity in the electrical path, full tension connectors are also designed to provide adequate mechanical strength to fully develop the conductor's strength. Splice connectors are used to join the ends of the conductors in span, and dead-ends are used to join conductors to attachment hardware on deadened structures. Typical types of full tension connectors are one and two piece compression connectors, formed-wire splices, implosive connectors, and wedge type connectors. Although the term "full tension" is commonly used for the mechanical holding strength of splices and dead-ends, they are typically designed to hold a minimum of 95% of the conductor's rated strength. The main consideration for connectors when evaluating elevated conductor temperature operations is its impact on the connector’s long-term service. High temperature excursions of connectors increase their electrical, mechanical, and thermal stresses, which, if severe and/or frequent, can undermine the integrity of the connector. Failure of connectors can be precipitated by high current and/or high temperature operations. Such failures can be difficult to predict and find. In addition, they are usually expensive and result in extensive field repair work and loss in transmission capacity. Since the final stage of failure is the parting of the conductor, there are also safety issues to consider. Connector Breakdown Process A connector accomplishes current transfer through numerous contact points between the connector and conductor. High current densities and high operating temperatures tend to encourage the build-up of resistive compounds at these contact point sites, which reduce their effective size, or completely close off current flow. The connector will reestablish new contact points at locations within the connector, which do not have a build up, of resistive compounds. The re-establishment of contact points within the connector can be thought of as an "aging" 5-20
process, where the connector will continue to provide good performance as long as there are locations where contact points can be easily established. Once the connector has aged such that all locations for easily establishing contact points are exhausted, the connector is forced to establish contact points through resistive compounds to reach the parent metal. This increases the overall resistance of the connector, its operating temperature, and current density within the remaining contact points. Once in this mode of operation, higher current densities and operating temperatures encourage further build up of resistive compounds, which further drive up current density and operating temperatures resulting in electrical failure. This electrical failure of a connector will mature into a thermal failure, detectable with thermal sensing equipment. If allowed to continue, the thermal failure will induce mechanical failure where the connector locally heats the conductor to temperatures where it becomes so hot, the conductor softens and eventually parts. Elevated temperature operations of conductors’ will increase the current density and operating temperature of associated connectors. This increase in service duty for connectors will accelerate their aging process, effectively reducing service life. The amount of accelerated aging connectors experience is related to the magnitude and frequency of elevated current and operating temperature excursions. Unfortunately, the relationship between connector aging and service duty is nonlinear and little success has been achieved in directly quantifying that relationship. Most well designed connectors (when properly installed) are capable of operating at high current densities and high conductor temperatures with acceptable long-term service. The current cycle test (Ref. 13), an industry standard, is used to evaluate these connector designs. Current cycling the connector results in thermal expansion and contraction of the electrical contact interface, which tends to break down the contact points. Although this standard test identifies procedures and qualification criteria for connectors use under normal operating conditions, it does have its limitations. The test requires a modest conductor temperature of only 100°C above ambient temperature and does not evaluate the effects of fault current nor atmospheric or industrial contamination. Recognizing that generalizations should be used cautiously, connectors that maintain satisfactory contact pressure over adequate contact areas, plus maintain low operating temperatures will exhibit better long-term service than connectors exhibiting lesser values of contact pressure and/or higher operating temperatures. For this Guide, connectors shall be considered failed if their operating temperature exceeds the temperature of the conductor to which they are attached. It can be argued that a connector operating in this mode has previously failed, and it can also be argued that a connector has not failed until the conductor has parted interrupting electrical continuity. However, “failed” field connectors are very difficult to detect until operating in thermal failure mode, and such operation is usually a precursor to imminent conductor parting. High Temperature Effects on Connector Joint Compound Most aluminum connectors (particularly compression type) employ a viscous compound in the interface between the connector and underlying conductor. The primary purpose of the joint compound is to provide a barrier that prevents moisture and other contaminants from leaching into the joint. Numerous excursions to high operating temperatures (connector temperatures 5-21
above 200°F - Ref. 9) can degrade the joint interface through compound evaporating in place and/or boiling the compound out of the connector-conductor joint. Joint compound evaporation will leave a shrunken and hardened residue no longer effective as a moisture barrier, and joint compound boiling expels the compound rendering a fitting no longer protected against moisture and contaminants leaching into the connector-conductor interface. The presence of moisture and contaminants in the joint will accelerate the connectors aging process and effectively shorten the connector’s service life. New and Existing Connectors When designing overhead power lines for high temperature operation, consideration should be given to the conductor temperatures at which the connectors were tested. Prudence dictates that connectors designed for high temperature operation should be tested and qualified for temperatures in excess of those expected in service. It is well known that electrical connectors that operate satisfactorily at one conductor temperature may not be suitable for higher conductor temperatures. When evaluating existing connectors for operation at higher temperatures, a review of the standards against which the connectors were designed and tested for helps in evaluating whether they are acceptable for increased service duty. Operating electrical connectors at temperatures above those for which they were designed can be risky. If a standard current-cycle test were not available, performing it on a specific connector design would provide additional information in evaluating the limits of a connector's service duty. Mitigation of Connector High Temperature Operations Reinforcing Existing Connectors - Existing connectors that are suspected of being inadequate for high temperature operations can be shunted to reduce their electrical loading and prolong their service life. Shunts provide an alternate path for current flow thereby reducing the connector’s current density and operating temperature. The reduction in connector current density retards the connectors aging process, and enhances its long-term service life. Shunting of marginal connectors to enhance long-term survival is appropriate for field connectors that have not yet failed. Repair of Failed Connectors - Repair of failed connectors where the conductor has parted involves cutting out the connector and adjacent annealed conductor, thoroughly cleaning the undamaged conductor ends and installing new connectors. When connectors are found failed but have not parted the conductor (usually with some type of thermal-vision device), the repair is the same as a parted conductor; cut out the failed connector and properly install a new replacement. As an interim measure however, the failed connector can be shunted reducing current density and operating temperature thereby retarding the breakdown process.
Conductor Hardware Conductor hardware, as used in this Guide, refers to non-current carrying devices attached directly to the conductor. Conductor hardware includes such standard devices as suspension
5-22
clamps (with and without armor rod), bolted strain clamps, armor grip suspension, dampers, spacers, and spacer-dampers. Insulators and other hardware not directly attached to the conductor are beyond the scope of this Guide. Connectors are covered in Section 5.0 “Connectors”. Metallic Conductor Hardware Metallic conductor hardware for aluminum conductors is fabricated primarily from aluminum alloys. Hardware for copper conductors is fabricated primarily from copper alloys. This practice recognizes the galvanic reaction between copper and aluminum when the two dissimilar metals are brought together in the presence of moisture. Galvanized ferrous hardware components have had extensive use because of their high strength-to-weight ratio and their being relatively galvanically inert to both aluminum and copper in mild atmospheres. High Temperature Effects of Ferrous Conductor Hardware - Ferrous hardware which surrounds, or partly surrounds, a conductor is subject to hysteresis and eddy current losses due to the magnetic flux associated with conductor current flow. These losses manifest themselves as heat gain within the hardware, and hence increase operating temperatures. Hardware operating temperatures greater than the conductor's allowable temperature for annealing may result in an unacceptable localized loss of conductor strength. The localized loss of conductor strength is confined to the conductor directly under and adjacent to the hardware. Heat gain due to hysteresis and eddy current losses in ferrous hardware is a function of conductor current magnitude and hardware thermal conductivity. Convection and radiation heat losses from the ferrous hardware are primarily a function of hardware surface area and surrounding ambient conditions. Hence, ferrous hardware operating temperatures will fluctuate in response to changing current flow and ambient conditions such that an equilibrium hardware temperature will be maintained balancing heat gain against heat loss. Current magnitude, ambient temperature, and the hardware’s mass to surface area ratio will largely influence this equilibrium temperature. Conductor hardware is employed in numerous applications to support and protect the conductor and is available in many different sizes and shapes. Smaller versions of ferrous hardware have a relatively low ratio of mass to surface area and usually operate at temperatures well below that of the conductor, regardless of current. Conversely, larger versions of ferrous hardware have a mass to surface area ratio that can result in hardware temperatures greater than the conductor’s allowable annealing temperature at higher currents. Hardware large enough to produce localized conductor temperatures of concern are usually confined to suspension and strain clamps, but can be any ferrous device surrounding the conductor with a large mass to surface area ratio. Published literature, which quantifies the localized increase in conductor temperatures as a function of current flow for ferrous hardware, is limited. Mitigating the effects of localized heating under ferrous hardware usually involves either limiting the current rating of a line, limiting the cumulative time a conductor can operate at an elevated rating, or replacing the hardware with non-ferrous hardware. Since the possible conductor/hardware combinations are extensive, no preferred mitigating technique has emerged within the utility industry. Such mitigation tends to be utility specific and often involves a combination of various techniques. 5-23
Nonferrous conductor hardware does not have internal heat generation due to conductor current flow. Such hardware also increases the local radiating surface area. Hence, nonferrous hardware usually operates cooler than the conductor to which it is attached. Non-Metallic Conductor Hardware Nonmetallic conductor hardware is generally limited to elastomeric compounds, which serve as compressive "bushings" within a hardware assembly. Compression bushings are typically used in spacers, spacer-dampers, and armor grip suspension clamps to provide a resilient interface between the conductor and the hardware. Publications concerning the effects of high temperature operations on elastomeric hardware components are limited. During and after high temperature excursions the elastomeric components must retain their resilient and semi-conductive properties for long-term survival. Loss of such properties can result in component deterioration and/or component failure.
5-24
6 UPRATING BY INCREASING THE MAXIMUM ALLOWABLE CONDUCTOR TEMPERATURE In this section, we will consider methods to increase the rating of an existing line without reconductoring it. Whatever method is chosen, since the transmission conductors are not to be replaced, the result will be operation at increased temperature levels. Consequently, the conductor, its hardware, and its connectors need extensive inspections prior to uprating and any questionable elements need replacement. In addition to a physical inspection, the engineer in charge of the uprating process must verify that adequate electrical clearances will be maintained after the uprating is complete. Typically, this verification consists of two parts: (1) measurement of sag clearance under everyday modest electrical load, and (2) calculation of minimum sag clearances under maximum electrical loading. A third step that should be taken (but seldom is) is experimental verification of electrical clearances under a combination of rated load and worst-case weather conditions. If the conductor of an existing line is not replaced, the only way the line rating can be increased is by increasing the maximum allowable conductor temperature. Since the maximum allowable temperature is increased, the additional sag must not violate electrical clearance requirements, nor the increased annealing of the conductor reduce the safety factor under maximum loading to an unacceptable level.
Evaluating Sag Clearance under Everyday Loading As discussed in Section 3, new lines must be designed to meet certain minimum electrical clearances over the whole life of the line and to limit the maximum tension under maximum ice and wind loads to the structure design values. To do this, initial unloaded sags are specified such that the final sags at high temperatures and the maximum tensions under ice and/or wind loading are within these limiting values. This is accomplished by specifying the initial sags and adjusting the initial sags (“stringing sags”) during construction with the conductor at a temperature in the range of 15oC to 25oC. The increase in sag due to creep elongation of aluminum and plastic elongation due to ice and wind loads is calculated based on estimates of what the line will see over its lifetime. Because of uncertainties in these calculations, new lines are typically designed with clearance buffers of at least 1 meter (3 feet). On existing lines, especially those that have been in service for 10 years or more, the sag at the maximum design temperature can be specified with improved accuracy. Only the thermal elongation of the conductor is uncertain. This may offer the opportunity to utilize excess clearance in order to operate the existing line at a temperature above the original design value thus increasing its rating. Many different techniques are available to determine the electrical clearance under everyday loadings. These range from the use of survey crews at selected spans, to flying the span by
6-1
airplane or helicopter with digital recording devices. The latter provides more data than required and costs more. The former provides less data than one might wish for and costs less. Particularly with digital recording from the air, the data can be loaded directly into line profiling and design programs like PLS-CADD and TL-CADD. This allows a span-by-span verification of sag and a relatively straightforward calculation of conductor sag at higher temperatures. While the accuracy of these measurements is in the range of a few inches, the determination of the corresponding conductor temperature at the time the conductor position is measured is less accurate. Generally, the conductor temperature is determined by use of a heat balance equation such as IEEE738 or DYNAMP with the line electrical load and local weather data.
Predicting High Temperature Sag and Tension – Homogeneous Conductors. The thermal elongation of stranded conductors is essentially the same as that of its component strands. Therefore, for an all aluminum or copper conductor, once the sag at “final” everyday conditions is established, the sag at high temperatures can be calculated with small uncertainty. Table 6-1 Sag-tension Calculations for 37 AAC (Arbutus) ALUMINUM COMPANY OF AMERICAN SAG AND TENSION DATA Conductor Arbutus
795.0Kcmil
37 Strands AAC
Area = .6234 Sq. In
Dia + 1.026 In
Wt = .746 Lb/F
RTS= 13900 Lb
Span + 600.0 Feet
Creep is a Factor
NESC Medium Load Zone
Design Points
Final
Initial
Temp F
Ice In
Wind Psf
K LB/F
Weight Lb/F
Sag Ft
Tension Lb
Sag Ft
Tension Lb
15.
.25
4.00
.20
1.451
12.02
5446.
10.65
6140
32.
.25
.00
.00
1.143
12.00
4294.
10.06
5118
0.
.00
.00
.00
.746
8.77
3833.
6.63
5067.
15.
.00
.00
.00
.746
9.67
3475.*
7.27
4621.
30.
.00
.00
.00
.746
10.58
3179.
7.98
4212.
60.
.00
.00
.00
.746
12.34
2727.
9.54
3524.
90.
.00
.00
.00
.746
13.99
2406.
11.19
3006.
120.
.00
.00
.00
.746
15.54
2167.
12.82
2624.
167.
.00
.00
.00
.746
17.78
1897.
15.24
2210.
212.
.00
.00
.00
.746
19.73
1711.
17.37
1941.
257.
.00
.00
.00
.746
21.54
1570.
19.33
1746.
302.
.00
.00
.00
.746
23.22
1457.
21.15
1598.
*Design Condition
6-2
For example, consider a line section of an all-aluminum, 37 strand (Arbutus) conductor having a ruling span of 600 ft (183 meters) installed to meet the following constraints: maximum tension of 50%, 33% initial unloaded at 15°F and 25% final unloaded at 15°F (-9.4 °C). An equally typical SAG10 program line design sag-tension run is in the following tabular output. In this example, we will assume that the line was originally designed for a maximum conductor temperature of 120 °F (49 °C) and that the line structures were placed such that the minimum ground clearances are met at a final ruling span sag of 15.5 ft (4.7 m). In order to operate the existing line at 167°F (75 °C), the attachment points must be raised approximately 2.2 ft (0.67 m). To operate at 212°F (100 °C), the attachment points must be raised approximately 4.2 ft (1.28 m). In existing lines having longer ruling span sections, there are fewer structures per mile (km) but longer ruling span correspond to greater sag increases with temperatures as shown in Figure .
Sag Change with Conductor Temp [120F (50C) to 212F (100C)]
Ruling Span - ft
1200
900
600
300
0.00
0.20
0.40
0.60
0.80
1.00
Sag Change in feet per 10 deg C AAC Figure 6-1 Change in Sag for All Aluminum Conductor as a Function of Span Length
6-3
1.20
1.40
Predicting High Temperature Sag and Tension – Non-homogeneous Conductors. As described previously in section 5, the thermal elongation of ACSR conductor is less than it is for an all aluminum conductor because the steel core has a coefficient of thermal elongation which is half that of aluminum. Therefore, older lines (which often have relatively small conductors with high steel content) sag less than all aluminum conductors for the same change in temperature. The degree to which an ACSR conductor’s thermal expansion is less than that of an all aluminum conductor (AAC), is dependent on the ratio of the steel to aluminum area. This ratio expressed as a percentage is usually referred to as the ACSR “Type” number. The following table lists the composite thermal elongation of ACSR conductors with different type numbers: Typical values for the coefficient of thermal expansion (α) of an ACSR are: Table 6-2 Coefficients of Thermal Expansion Type Number
α (per degree C)
AAC
0
23.0x10-6
36/1 ACSR
3
22.0x10-6
18/1 ACSR
5
21.1x10-6
45/7 ACSR
7
20.7x10-6
54/7 ACSR
13
19.5x10-6
26/7 ACSR
16
18.9x10-6
30/7 or 30/19 ACSR
23
17.5x10-6
Conductor
Notice, however, that although we have listed composite thermal elongation coefficients for ACSR, in reality the aluminum strands elongate at twice the rate of the steel strands. The reduced thermal elongation coefficient of the composite is actually the result of both this difference in expansion with temperature and the change in component tensions that it produces. Ignoring Aluminum Compression in ACSR Over the past 40 years, the Varney graphical method is the bases of most Sag-tension programs. The Alcoa SAG10 program is widely used. The following sag-tension table uses the SAG10 program. It shows the sag and tension (total, aluminum and steel component tensions) for initial and final conditions for 45/7, 795 kcmil ACSR (Tern) initially sagged so as not to exceed a final unloaded tension of 5525 lbs (25% of Tern’s Rated Breaking Strength of 22,100 lbs). NESC Medium Loading conditions and conductor temperatures up to 302oF (150oC) are included.
6-4
Table 6-3 Sag-Tension Calculations for 37 AAC (Arbutus) ALUMINUM COMPANY OF AMERICAN SAG AND TENSION DATA Conductor Arbutus
795.0Kcmil
37 Strands AAC
Area = .6234 Sq. In
Dia + 1.026 In
Wt = .746 Lb/F
RTS= 13900 LB
Span + 600.0 Feet
Creep is a Factor
NESC Medium Load Zone
Design Points
Final
Initial
Temp F
Ice In
Wind Psf
K LB/F
Weight Lb/F
Sag Ft
Tension Lbs
Sag Ft
Tension Lbs
15.
.25
4.00
.20
1.605
9.73
7429. 5618.A 1811.S
8.48
8527. 6843.A 1684.S
32.
.25
.00
.00
1.304
9.62
6109. 4449.A 1660.S
7.90
7434. 5953.A 1480.S
0.
.00
.00
.00
.896
6.57
6137. 4671.A 1466.S
5.16
7823. 6412.A 1411.S
15.
.00
.00
.00
.896
7.30
5525.* 4084.A 1441.S
5.57
7243. 5904.A 1339.S
30.
.00
.00
.00
.896
8.08
4996. 3565.A 1431.S
6.05
6668. 5392.A 1277.S
60.
.00
.00
.00
.896
9.70
4164. 2708.A 1456.S
7.22
5588. 4400.A 1189.S
90.
.00
.00
.00
.896
11.31
3571. 2043.A 1528.S
8.63
4675. 3516.A 1159.S
120.
.00
.00
.00
.896
12.86
3142. 1511.A 1631.S
10.18
3967. 2781.A 1186.S
167.
.00
.00
.00
.896
15.13
2675. 842.A 1833.S
12.62
3203. 1892.A 1311.S
212.
.00
.00
.00
.896
17.10
2368. 314.A 2054.S
14.81
2731. 1242.A 1490.S
257.
.00
.00
.00
.896
18.59
2180. 0.A 2180.S
16.83
2406. 706.A 1700.S
302.
.00
.00
.00
.896
19.37
2094. 0.A 2094.S
18.69
2168. 239.A 1929.S
*Design Condition
6-5
Table 6-4 Sag-tension Calculations for 37 AAC (Arbutus) ALUMINUM COMPANY OF AMERICAN SAG AND TENSION DATA Conductor Arbutus
795.0Kcmil
37 Strands AAC
Area = .6234 Sq.In
Dia + 1.026 In
Wt = .746 Lb/F
RTS= 13900 LB
Span + 600.0 Feet
Creep is a Factor
NESC Medium Load Zone
Design Points
Final
Initial
Temp F
Ice In
Wind Psf
K LB/F
Weight Lb/F
Sag Ft
Tension Lb
Sag Ft
Tension Lb
15.
.25
4.00
.20
1.955
7.80
11283. 3423.A 7859.S
6.83
12880. 4986.A 7894.S
32.
.25
.00
.00
1.667
7.68
9773. 2377.A 7395.S
6.36
11804. 4462.A 7342.S
0.
.00
.00
.00
1.235
5.30
10495. 3193.A 7302.S
4.45
12499. 4972.A 7527.S
15.
.00
.00
.00
1.235
5.79
9600.* 2508.A 7092.S
4.69
11864. 4623.A 7242.S
30.
.00
.00
.00
1.235
6.34
8775. 1860.A 6914.S
4.95
11241. 4277.A 6963.S
60.
.00
.00
.00
1.235
7.56
7357. 693.A 6664.S
5.54
10039. 3605.A 6435.S
90.
.00
.00
.00
1.235
8.65
6432. 0.A 6432.S
6.23
8921. 2966.A 5955.S
120.
.00
.00
.00
1.235
9.26
6010. 0.A 6010.S
7.03
7910. 2373.A 5537.S
167.
.00
.00
.00
1.235
10.27
5422.S 0.A 5422.S
8.45
6580. 1553.A 5027.S
212.
.00
.00
.00
1.235
11.27
4939. 0.A 4939.S
9.94
5600. 894.A 4706.S
257.
.00
.00
.00
1.235
12.30
4528. 0.A 4528.S
11.45
4864. 343.A 4522.S
302.
.00
.00
.00
1.235
13.34
4178. 0.A 4178.S
12.80
4352. 0.A 4352.S
*Design Condition
6-6
With reference to this table, notice the following: •
The difference in sag-tension between “initial” and “final” conditions is due to everyday creep elongation rather than high-tension events due to ice and wind.
•
The total conductor tension decreases with time (i.e. between initial and final conditions) and with conductor temperature, but the tension in the component steel core strands increases.
•
The aluminum strand component tension becomes zero at 257oF (125 oC) under final conditions and remains zero as the temperature increases further to 302oF (150 oC). 257oF (125 oC) is the “knee point” temperature of the line beyond which the sag increases at a lower rate.
Next, compare the preceding sag-tension behavior for 45/7 ACSR (Tern) with the following table for 30/19 ACSR (Mallard) (also 795 kcmil) installed to the same final unloaded 25% RBS tension at 60oF (15.5 oC). Notice that the knee point temperature, under final conditions, is only 90oF (32 oC). Figure 6-2 shows final sag versus conductor temperature for ACSR (Mallard) in four different ruling span lengths. Note the change in slope of the curves below 50oC where the knee point occurs.
Sag versus Conductor Temperature for 30/19 ACSR 40.0 Ruling Span Sag - ft
35.0 30.0 25.0 20.0 15.0 10.0 5.0 0.0 -50.0
0.0
50.0
100.0
150.0
Conductor Temperature - deg C 300ft
600ft
900ft
1200ft
Figure 6-2 Sag for a "Strong" ACSR Conductor as a Function of Conductor Temperature and Ruling Span Length
Many older lines that are typical candidates for uprating were designed with high steel ACSR such as 30/19, 30/7, and 26/7. The low thermal elongation beyond the knee point temperature, illustrated in the preceding calculations, makes these older lines attractive candidates for 6-7
operation at higher temperatures. Figure 6-3 confirms that this lower sag increase rate at high temperature makes a large difference in uprating calculations, which compares the sag increase rates between 100 °C and 150 °C for a “low steel” ACSR (45/7), a high steel ACSR (30/19), and an all aluminum conductor. The “knee point” for 45/7 ACSR occurs at a higher temperature than for 30/19 since there is less steel in this Type 7 ACSR. It is also a function of ruling span length being 85 °C for 300 ft (91 m), 115 °C for 600 ft (183 m), 145 °C for 900 ft (274 m), and 155 °C for 1200 ft (366 m). Therefore, the sag increase rate for 45/7 is comparable to AAC at the larger spans but much less for the smaller spans.
Sag Change with Conductor Temp [100C to 150C]
Ruling Span - ft
1200
900
600
300 0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
Sag Change in feet per 10 deg C AAC
45/7ACSR
30/19ACSR
Figure 6-3 Comparison of Sag Change with Temperature for All Aluminum Conductor, 45/7 (Type 7) ACSR, and 30/19 (Type 23) ACSR
Accounting for Aluminum Compression in ACSR Starting with the studies of Barrett at Ontario Hydro, the assumption of zero compressive stress in ACSR beyond the knee point temperature has come into question. The question centers not on the correct calculation of the knee point temperature but on whether the aluminum strands can support compressive stresses above it. The Canadian Electrical Association’s STESS software program incorporated Barrett’s research.. Inclusion of the compressive effects of the aluminum strands of high steel content conductors such as 26/7 ACSR (Drake) can add as much as 3 feet (0.91 m) to the sag at 150oC in a 1200 ft (366 m) span. The effect is less with smaller ruling spans and with lower conductor temperatures. 6-8
Recent studies by Rawlins seem to confirm the existence of compressive effects as well as residual stresses (due to manufacturing) in aluminum strands at high temperatures. The effect on sag at high temperatures appears to be much smaller than those predicted by Barrett. The widely used SAG10 program has incorporated Rawlin’s studies’ as an optional calculation. In a 1200 ft (366 m) span, Rawlin’s method would add about 1 ft (30 cm) to the sag of a high steel conductor such as Drake at 150oC. Figure 6-4 shows a comparison of sag as a function of conductor temperature calculated with the following assumptions: •
The SAG10 computer program with an assumption of zero compressive stress in the aluminum strands.
•
The SAG10 computer program with the default assumption of 2500 psi residual stress and allowance for aluminum compression.
•
The STESS computer program with the default assumption of 10 MPa for maximum compressive stress and no residual stress. High Temp Sag Comparison 600 ft span of Mallard ACSR
16
15
14
13
SAg - ft
12
11
10
9
8
7
6 0
20
40
60
80
100
120
140
160
Conductor Temp - C no comp
SAG10
STESS
Figure 6-4 Sag at High Temperatures Calculated with and without Aluminum Compression
Figure is a similar plot that shows the somewhat larger sag differences that occur in a 1200 foot ruling span. 6-9
High Temp Sag Comparison 1200 ft span of Mallard ACSR
41
39
37
Sag - ft
35
33
31
29
27
25 0
20
40
60
80
100
120
140
160
Conductor Temp - C no comp
SAG10
STESS
Figure 6-5 Final Sags for Mallard ACSR in a 1200 ft span.
At this point, there is no clear way to determine which of these methods is correct. Indeed, there is no way to be certain that the stress assumptions for either are correct. However, there is a distinct possibility that the original line design calculations of final high temperature sag were too small. There is also some uncertainty as to how much the sag should be increased to be certain that electrical clearances will be maintained at an increased maximum conductor temperature. Measurement of Sag-Tension at High Temperatures One way to verify the high temperature sag-tension behavior of any overhead line is to measure the sag or tension with a monitoring device during a period of high current loading and worstcase weather conditions. During several field tests sponsored by EPRI, tension monitors were installed on a 230-kV line with 30/19 ACSR (Mallard) conductor. The line was rated for a maximum conductor temperature of 100oC. Figure 6-6 is a plot of line tension during a period of exceptionally high current loading. Note that the line tension is below the maximum design tension used during its construction.
6-10
Line Tension (lbs)
Line Tension Measurements for July 1995 15 min sampling (5 min avgs) Minimum Line Design Tension = 5500 lbs
6300 5800 5300 july_15min.xls
4800 0.0
200.0
400.0
600.0
800.0
1000.0
Line Current (amps) Figure 6-6 Measured Line Tension as a Function of Line Current for a Line with 30/19 Mallard ACSR
Direct measurement is the best way to verify high temperature sag behavior, but these measurements are optimized when the line current is at high levels, and kept high over a long enough period to include worst-case weather conditions.
Conductor and Connector Inspection Techniques Although a number of uprating methods are discussed in this section, the need for a thorough line inspection prior to the implementation of any method which results in increase line current is clear. Prior to any increase in ratings, damaged conductors or corroded connectors need replacement. International Council on Large Electric Systems (CIGRE) recently published an excellent paper on the inspection of connector “joints”.
Re-Tensioning & Wind-Induced Conductor Motions On an existing line, originally installed at a modest tension, it may be possible to operate at an increased maximum temperature without extensive modification to the structures.
Raising Attachment Points In most existing lines, whose maximum allowable conductor temperature is determined by electrical clearance, only certain spans may be limiting.
6-11
7 PROBABILISTIC METHODS OF LINE UPRATING Of the three major types of power equipment – underground cables, overhead lines, and power transformers – overhead lines react most quickly to changes in current and weather. Overhead lines are the only type of power equipment that may directly impact public safety through inadequate electrical clearance. The NESC specifies minimum clearances for high voltage overhead lines that must be met at “the maximum conductor temperature for which the line is designed to operate….” Therefore, in the United States, it is generally not possible to specify the electrical clearances of a line probabilistically. That is, by specifying that the electrical clearances set by the NESC Code are met 99.99% of the time. In other countries, the use of such probabilistic clearances is acceptable. In fact, unless the line is designed with a very generous clearance buffer, electrical clearances may be violated during those relatively rare events when the line load equals the rating, and the actual weather conditions along the line are less “conservative” than the static rating assumptions. For example, with a transmission line designed to reach electrical clearance minimums at 100oC, whose Summer rating is based on a 3 ft/sec (0.91 m/sec) perpendicular wind and an air temperature of 35oC, the line’s clearances may be less than these minimums for wind speeds of less than 6 ft/sec (1.83 m/sec) blowing parallel to the line. It is important to understand how often this might occur and, if it never occurs, it may be possible to increase the rating of the line. Aside from the issue of clearances, the rating of lines having conductors with little or no steel (AAC, AAAC, ACAR, Cu, 45/7 ACSR, 18/1 ACSR, etc.) may be limited by concerns about loss of tensile strength. As described in section 5, aluminum and copper rapidly lose tensile strength when exposed to temperatures above 100oC. A careful review of cumulative loss of strength during periods of emergency loading may allow an increase in emergency ratings without the need for reconductoring. This section reviews two probabilistic rating calculations: 1. Probabilistic Clearance – Actual line ratings over an extended period are compared to the present static thermal rating. The static rating is assigned a certain probability of failure. The rating of the line may be increased if it is determined that minimum clearances are always met or if methods are available to reduce the load during periods of low rating. 2. Probabilistic Loss of Strength – Conductor temperatures during periods of high line current is calculated and the cumulative loss of strength over time is determined. If the cumulative loss of strength of the existing conductor under present allowable loads is acceptable, the line rating may be raised until the limits on loss of strength are reached. Note that in either case, the probability of success in using these methods to uprate existing lines depends on how conservative present static rating are.
7-1
Probabilistic Clearances If the weather along a transmission line is recorded over a period of months or years, it is possible to calculate the line rating for every 10 minutes during the period. Then, the resulting list of line ratings may be statistically analyzed in order to determine the probability that the line rating exceeds a range of values. This may also serve to provide a quantitative basis for any conventional static rating. Given the weather conditions, it is also possible to calculate the conductor temperature if the line current is specified for the study time period. The current may be actual recorded values of line load, a worst-case daily load cycle, or a constant load. In any event, the corresponding distribution of conductor temperatures, the sag distribution, and the cumulative strength distribution can be found. When these techniques are applied with the goal of increasing the line’s rating, either the probability of a clearance violation or the cumulative loss of conductor strength is found. The cumulative loss of conductor strength corresponds to a range of line electrical loadings. This is where the possibility of operation at higher line loads is evaluated.
Determining the Probability of Electrical Clearance Violations As mentioned in the preceding section, NESC electrical clearances are deterministic. That is, they are to be met all the time, under all operating conditions. Yet, the use of conservative weather conditions and conductor parameters is generally accepted practice even though it is widely understood and accepted that, if a transmission line carried a continuous line current equal to the static rating, clearance violations would be expected to occur with a frequency of between 5% and 50% of the time. Given this rather inconsistent and confusing situation, one can at least calculate the statistical distribution of line ratings and determine the frequency with which the actual line rating is less than the static rating. This is a good way to keep non-technical people from forcing the use of less conservative rating conditions as a method of saving money through the distinctly nontechnical process of hand-waving and bullying in meetings. A number of issues need to be addressed before undertaking this sort of analysis: •
How should the line current be modeled? Does one assume it is constant and equal to the static rating? Is it periodic over 24 hours with a peak value equal to the static rating? Is it equal to the static rating but limited in time (2 hours per year)?
•
How should the wind be modeled? How will the angle between the wind and the power line be represented? What sort of wind data is appropriate – weather bureau airport data; anemometer data along the line; or effective wind data from sag-tension monitors?
•
What will we define as a clearance violation? For example, is a single occurrence per year, where the sag in one span violates the minimum clearance by 6 inches (15 cm), the same as multiple occurrences per year, where the sag in multiple spans violates the minimum clearance by 2 to 3 feet (0.61 to 0.91 m)?
7-2
Probabilistic Loss of Strength On lines having copper (Cu) or all aluminum (AAC, AAAC, ACAR) conductors which have sufficient clearance to operate at an increased maximum allowable conductor temperature, but are limited from doing so by concerns over loss of tensile strength at temperatures above 90oC, it may be possible to take a probabilistic approach to uprating the line. The technical paper by Beers, Gilligan, Lis, and Schamberger is an excellent example of a practical method used to calculate the loss of tensile strength in transmission conductors as a function of loading and weather conditions. The method used to calculate the loss of tensile strength begins by using weather data from the U.S. Weather Bureau. Then, the conductor temperature is calculated using the House & Tuttle thermal heat balance model (similar to the IEEE 738-1993 method). Next, the loss in tensile strength is calculated according to data provided by Alcoa, assuming that a loss of strength of 12% to 15% in the aluminum strands is acceptable over a 30 year life span. Wind Speed Data Adjustments The authors recognized certain limitations in weather data provided by the U.S. Weather Bureau. Limitations include partial or complete stalling of Weather Bureau anemometers at wind speeds less than 3 knots (1.5 m/sec) and an acknowledgment that the Weather Bureau “…observations were made in elevated and exposed locations, while most of the lines run through hilly, wooded terrain, which may be quite sheltered from the wind.” The authors dealt with the errors due to anemometer stalling at low wind speeds by allocating the lowest wind speeds as shown in Figure 7-1. Note that a wind speed of 1.0 knots is equal to 1.69 ft/sec (0.515 m/s). While acknowledging the importance of low wind speeds to the loss of strength calculation (they do not even consider wind speeds above 10 ft/sec (3 m/sec)), the authors rationale for their allocation of wind speeds according to the curve in Figure 7-1 is simply that “it was decided to “smooth” the readings between zero and 4 knots (2.1 m/sec), assuming that the probability of a true zero velocity approached zero.” Next, the authors developed combined frequency of occurrence tables for air temperature and wind speed as shown in Table 7-1. The number of hours shown in this table is actually 4 times as many as was determined through analysis of Weather Bureau data in order to account for sheltering effects along the line.
7-3
Figure 7-1 Wind Speed Distribution at 70 °F Showing Actual Reported Values (Shown in Parentheses) and the Author’s Smoothed Distribution Curve. Table 7-1 Assumed Hours of Combined Wind and Air Temperature in 30 Years for a Typical Protected Transmission Line Right-of-Way. Ambient Temp
Wind Speed–ft/sec
Deg F
0.375
1.0
1.5
2.0
2.5
3.0
90
3
7
13
20
28
38
85
4
18
36
58
84
115
80
5
23
47
77
113
155
75
31
77
140
223
312
395
70
38
92
168
271
363
500
65
38
92
168
271
363
500
10
4
15
30
47
65
83
5
4
15
30
46
62
78
7-4
Load Current Assumptions and Annealing Calculation The authors used the annealing curves shown in Figure to estimate the conductor loss of strength. Note that the dashed zigzag line indicates how the cumulative annealing was calculated starting with 65oC. The line current load was assumed constant for all hours of the year and all years of the 30 years life. For a range of line currents, the corresponding conductor temperature was calculated for each of the air temperature and wind speed combinations and the annealing was found for that temperature and the number of hours. The authors found acceptable levels of strength reduction where the range of maximum conductor temperatures under still air conditions reached temperatures between 140oC and 180oC. Emergency and Normal Ratings The authors noted that it was excessively conservative to assume that the line current was constant even for normal rating calculations. For normal ratings, the authors suggested reducing the duration of all high temperature events by 95%. Thus, the 113 hours spent at an air temperature of 80oF and 2.5 ft/sec (0.76 m/sec) would be reduced to 6 hours. The authors also noted that contingency (emergency) loads are much less frequent and suggested a total of 600 hours randomly distributed over 30 years as a reasonable estimate.
Figure 7-2 Typical Annealing of Aluminum Wires (Alcoa)
7-5
In the appendix to the paper, the authors present the following ratings for transmission conductor. The total loss of strength due to operation with load current equal to the normal rating over 13,000 hours and equal to the post-contingency rating for 600 hours over 30 years is a cumulative loss of strength of 12% and 15%. Table 7-2 Conductor Ratings Based on 12% to 15% Loss of Aluminum Wire Strength Over 30 Years Where the Normal Load does not Occur for More than 13,000 Hours and the Contingency Load does not Occur for More than 600 Hours. The Loads are Assumed to be Random. ACSR Conductor
Rating-Amperes
Size (kcmil)
Stranding
Normal
Post-Contingency
2/0
6/1
270
320
4/0
6/1
400
470
336.4
18/1
580
685
336.4
26/7
610
725
397.5
18/1
660
770
556.5
24/7
860
1020
795
45/7
1075
1285
1113
45/7
1365
1640
1272
45/7
1475
1770
The authors note that a line current equal to the normal rating would result in a conductor temperature of 140 °C with zero wind at 90 °F (32 °C), and that a line current equal to the postcontingency rating would result in a conductor temperature of 180oC. They note that this applies for all the conductors considered and that the line clearance must be adequate for these conductor temperatures in order for these ratings to be valid. Limitations of the Probabilistic Approach There are a number of possible difficulties in the approach taken by the authors. In fact, there are a number of uncertainties to any such attempt to determine the rating of a line in terms of probabilistic loss of strength. A partial list of questions include: •
While the authors do not mention it specifically, it appears that the issue of wind direction was ignored. A wind speed of 6ft/sec (1.8 m/sec) nearly parallel to the line 7-6
will result in the same conductor temperature as a 2 ft/sec (1.8 m/sec) crosswind. It seems likely that the ratings derived in the study would be lower if wind direction was considered. •
The authors assumed that zero wind conditions never occur in their annealing calculations and that wind speeds of 1.0 ft/sec (0.3 m/sec) occur only 1/3 as often as winds of 2 ft/sec (1.8 m/sec). There is no evidence to support this. On the other hand, the frequency of occurrence of winds of 3 ft/sec (0.91 m/sec) and below is responsible for almost all of the significant annealing that occurs.
•
Ratings and peak normal or post-contingency emergency load events may be correlated. The authors of this study assumed that peak normal ratings occur only 5% of the time, and they also assumed that such peak current events occurred randomly.
•
While the authors considered the possibility of seasonal ratings (summer and winter), they ignored daily variations driven by solar heating. There is considerable evidence in recent years that peak ratings often occur in the afternoon and minimum ratings are at night.
•
Most lines with ACSR conductor are clearance limited. That is, the maximum allowable conductor temperature is determined by the need to maintain ground clearance rather than by the need to limit annealing of the aluminum strands.
•
The authors did not consider the possibility that such high temperatures may cause increased permanent sag due to creep elongation. Conductors such as 45/7 and 18/1 ACSR do exhibit high temperature creep.
Simplified Method of Probabilistic Annealing Calculation The preceding study method is rather complex and time consuming, yet there appear to be significant questions about its accuracy. San Diego Gas & Electric (SDG&E) uses a much simpler method to determine post-contingency emergency ratings for ACAR and ACSR/AW lines. Normal ratings are calculated for a 2 ft/sec (0.61 m/sec) cross-wind at an air temperature of 100 ° F (38 °C) with sun. The maximum allowable conductor temperature for normal ratings is 90oC. Post-contingency emergency ratings are calculated for the same weather conditions, but the maximum allowable conductor temperature is specified such that the loss of tensile strength is just 5% after 1000 hours. This assumes the line current at the post-contingency emergency rating has the same conservative weather conditions used for normal ratings. The emergency MACT varies between 108oC and 120oC depending on conductor type and stranding. For example, one utility believes that the use of a 5% loss of strength criteria and allowing 1000 hours of emergency operation over the life of the line are conservative. Brief periods of still air coincident with a contingency would probably yield less than 10% loss of strength and 1000 hours of emergency operation is felt to be much more than is likely to occur.
7-7
8 DYNAMIC UPRATING METHODS If dynamic rating methods are applied to increase the effective rating of an overhead line, realtime weather data and optionally line temperature or sag-tension data must be communicated from multiple remote locations to the utility operations center where the line rating calculations are performed. In all such cases, the line rating is no longer constant but varies with weather conditions. This technology has been implemented at a number of EPRI member utilities and is worth considering in cases where there is a need for minimum capital investment, a modest increase in rating, combined with operational flexibility and available SCADA/EMS communications.
Where Dynamic Ratings Should Be Applied Uncertain Load Growth In a regulated environment, circuit load growth was predictable and corresponding increases in circuit capacity became part of the long term planning process. In a modern “open access” environment, circuit load growth is uncertain, and providing suitable increase in circuit capacity is problematic. In this environment, large capital expenditures are unattractive; a small increase in capacity that requires a correspondingly small capital investment appears to be an attractive alternative. Independent power generators are encouraged to build their facilities in areas that have immediate physical access to low cost fuels. The siting of these generating facilities and their magnitude is not predictable years in advance as was true in the previous regulated environment. Therefore the transmission system operator is asked to respond quickly, to provide capacity in a time frame which is much less than that required for the siting and approval of new lines. Maintain Reliability Given the rapidly changing utility business, utilities are hesitant to make the large capital investments required to build new facilities. As a result, power utility engineers are under pressure to make greater use of existing power equipment while maintaining or improving the reliability of an increasingly aged transmission system. In a regulated business environment, the transmission system operator had little reason not to provide generous transmission capacity, since return on investment was guaranteed. In an unregulated environment, it is anticipated that transmission facilities will be much more heavily utilized and are more likely to approach or exceed their operating limits. This is likely to have an impact on transmission reliability.
8-1
One of the benefits of real-time thermal monitoring is the improved understanding gained of how power equipment behaves when subjected to heavy electrical loading. Such high loading events in a regulated environment were rare. Errors in thermal modeling of equipment may well have gone unnoticed since the loadings were modest. Any theory works just fine as long as there is no measurement to disprove it. Open Access & Economic Transfers In an “open access” utility environment, capacity limitations can be very expensive and even modest increases in capacity can result in huge economic advantages. Uprating methods such as the EPRI DTCR method offer a flexible low cost method of meeting the need for capacity increases with small capital investment. One of the unique aspects of dynamic transmission circuit rating (DTCR) is that it may be applied to several circuits in the same general geographical area since they share the same weather conditions. Thus, for essentially the cost of monitoring and rating one of the circuits, several such circuits may be dynamically rated. This makes DTCR attractive as a method of increasing “transfer” limits as well as circuit limits.
Dynamic versus Static Uprating Figure 8-1 illustrates the difference between dynamic ratings and static ratings. The right-most bell shaped curve represents the probability distribution of line thermal ratings calculated based upon real-time field monitors. Note that the ratings of the line typically vary over a range of more than 2:1. The very lowest ratings correspond to still air, maximum air temperatures, and full sun. A typical static thermal rating of 800 Amperes is shown at the left tail of the rating distribution. A less conservative static rating of about 900 amps is also shown. Clearly, the higher the static rating, the more frequently the actual real-time rating is less when compared to the static rating. The left-most distributions are line loadings (which vary as a result of varying customer load levels and system configuration changes) appropriate to each of the static ratings. Note that the line loadings approach but do not exceed the static ratings, and for each loading curve the load may occasionally exceed the dynamic rating. This happens more frequently (larger overlap area) for the higher load distribution. The advantage of using dynamic line ratings is clear from Figure 8-1. The dynamic line rating is higher than the static rating most of the time, and the operator knows when the line rating is low and is able to avoid clearance infringements by reducing line load temporarily. The disadvantage of dynamic thermal ratings centers on the difficulty system operators have in utilizing variable ratings in light of their need to make contract commitments and allow maintenance outages up to 24 hours in advance.
8-2
INCREASING LINE UTILIZATION WHILE REDUCING RISK BY DYNAMIC RATING 0.45
LOAD DISTRIBUTION INCREASES AS A RESULT OF NEW HIGHER RATING
0.40
PROBABILITY DENSITY
0.35
ACTUAL DYNAMIC RATING DISTRIBUTION
0.30
New, less conservative rating
0.25
LOAD1 LOAD2 RATING
0.20
Old, fixed rating 0.15
DYNAMIC "LOW RATING" WARNING PROVIDED TO OPERATOR IF
0.10
0.05
0.00 0
200
400
600
800
1000
AMPERES
1200
1400
1600
PTINEWS_LDVSRAT1.xls
Figure 8-1 Probability Density Distributions for a Typical Circuit Load and Dynamic Rating
Dynamic Ratings are Normally Higher than Static Ratings Calculating dynamic equipment ratings based on actual rather than worst-case estimates of weather and electrical load is primarily attractive because the ratings are usually higher than normal static ratings. The advantages gained in implementing dynamic rating methods depend on just how conservative the worst case rating assumptions are. Occasional Damage Avoided In a regulated business environment, under ordinary operating conditions, power equipment was lightly loaded. High electrical loadings were rare; hence, the precise determination of high temperature behavior was not critical. Some years ago, however, as the regulation of utility business began to decrease, EPRI recognized that increasingly aged power equipment was being operated at higher and higher load levels. This might lead to increased failure rates and consequent service outages unless the mathematical models used to specify load limits were refined and critical equipment parameters verified by measurement.
8-3
An Alternative to Less-Conservative Static Ratings Driven by the advent of open transmission access and deregulation of the utility business, there has been a distinct trend toward the use of less conservative rating assumptions with little or no basis in science. Field testing of dynamic thermal methods offered an opportunity both to evaluate the possible increase in ratings and to detect the frequency of occurrences where existing equipment might be damaged due to less conservative rating assumptions. Calculation of thermal ratings for overhead lines are typically based upon heat balance methods such as that found in IEEE 738-1993. Given a maximum allowable conductor temperature, the corresponding maximum allowable current (the thermal rating) is determined for “worst-case” weather conditions. Maximum allowable conductor temperatures typically range from 50 °C to 150 °C. Typical “worst-case” weather conditions are a wind speed of 2 ft/sec (0.61 m/sec) perpendicular to the conductor, with full solar heating and an air temperature of 30 °C to 40 °C. Table 8-1 illustrates the advantage of assuming a higher wind speed and the consequence of doing so. Use of a higher wind speed for thermal rating calculations yields an increase in the line rating even though the maximum conductor temperature (100 °C) remains the same. For example, an increase in assumed wind speed from 2 to 3 ft/sec (0.61 m/sec to 0.91 m/sec) yields an increase in the rating from 990 to 1080 Amperes and, since the assumed conductor temperature remains the same, no line modifications are required. Table 8-1 Effect of Assumed Wind Speed on Thermal Rating for Drake 795 kcmil ACSR at 100°°C, Assuming Full Sun and an Air Temperature of 40°°C Assumed Wind Speed for Line Rating Calculation
Line Rating for 795 kcmil ACSR @ 100°°C
Conductor Temperature when current=rating & windspeed=0 ft/sec (0m/sec)
(ft/sec)
(m/sec)
(Amperes)
(°C)
0
0
750
100
2
0.61
990
130
3
0.91
1080
145
4
1.22
1160
160
The major advantage of this method of uprating is clear - it is very inexpensive. Since the maximum allowable conductor temperature remains the same (100 °C), the corresponding maximum sag is unchanged and no line modifications are required. The major disadvantage of this approach is also clear from the rightmost column of Table 8-1. This column shows the temperature attained by the conductor for still air conditions (0 ft/sec, or 0 m/sec), with a line load equal to the calculated rating shown in column 2. Historically, the joint probability of maximum loading and worst-case weather was considered a rare event. Recent field studies indicate that, in certain areas, the probability of still air may be in excess of 10%. Combined with the previously noted increase in normal and emergency line loading, the
8-4
temperatures indicated in the last column of Table 8-1 may be a real concern, and the use of a less conservative wind assumption may impact line reliability.
Real-time Monitoring Methods The maximum electrical power flow down an overhead transmission line is typically determined by the need to limit conductor sag and thus maintain minimum ground clearances. Various monitoring methods have been proposed and tested, all of which are typically applied to determine the line’s sags in all it’s spans and the maximum current, which can be carried without violating minimum electrical clearance requirements in any span. The following real-time monitors are either commercially available or have been field-tested at a number of locations: Sag monitor - Real-time measurement of sag in each line section is the most direct method of determining that the electrical load of the line is safe. The sag (and ground clearance) in other spans of the same line section can be determined by calculations. Tension monitor – A load cell can be used to determine the line tension. The load cell is placed on the grounded side of dead-end insulator strings. In most cases, the measurement of line tension can accurately be converted to sag in all spans of the line section. Conductor temperature monitor – Conductor temperature monitor incorporates a clamp-on thermocouple, attached directly to the energized conductor and linked to a ground station by radio. The line’s sag-tension may be calculated from the average conductor temperature in the line section. The accuracy of temperature monitors depends on how close the measured conductor temperature is to the average line section temperature, and on the accuracy with which sag can be calculated from the average conductor temperature. Weather data monitors – Weather data monitors measure wind speed, direction, solar heating, and air temperature. Knowing the line current, the conductor temperature near the weather monitor can be estimated and based on the calculated conductor temperature; then, the sag and electrical clearance may be calculated. The monitoring methods can be divided into two categories; direct sag-tension and indirect sagtension methods. The following sections discuss each of the monitoring methods. Indirect Clearance Determination with Conductor Temperature or Weather Monitors Weather Data Monitors – Instruments to measure wind speed, wind direction, solar heating, and air temperature are placed at the height of the transmission line conductor, preferably in the transmission right-of-way. Weather data from airports and other commercial stations is likely to be inappropriate for real-time monitoring of lines. As in most monitoring methods, the line current is obtained from conventional current transformer measurements at a nearby substation. This method uses weather conditions, line current, and conductor parameters to calculate the temperature of the conductor. The conductor temperature is then used to determine the position
8-5
of the conductor in light of the sag-tension line design data. Alternatively, the conductor temperature is compared to the line design maximum allowable conductor temperature and it is assumed that if the design temperature is reached, then the safety limit is exceeded and there is risk to the public. The highest conductor temperature is obtained for the lowest wind speeds and those winds are nearly parallel to the line direction. Therefore, the wind anemometer must be of high quality, able to measure wind speeds below 1m/sec. The propeller type is more accurate than the cup type but both are subject to start-up error after stalling at low wind speed. The best results are often obtained from the ultrasonic type. Alone among the monitoring methods discussion in this guide, the accuracy of line ratings determined by weather monitoring are not dependent on the line current. This method may therefore be used to supplement the other monitor based dynamic rating methods. This method may not cater for variation in parameters that could affect the conductor temperature and hence sag. Variation in the value of the parameters can be caused by variability of the terrain or by the sheltering of a line by trees or buildings. In addition, wind speed and direction can differ from the point of measurement, (for example an airport) to the actual line. To mitigate the above effects there may be a need to install a number of weather stations along the (long) lines; associated communication problems to transmit the readings may occur together with uncertainty of the best location of weather stations. This is because the critical span could be varying. The calculations generally refer to the surface temperature of the conductor. Assumptions have to be made as to the total power input and the thermal conduction between strands to determine the average temperature of the conductor from which the sag can be determined. Conductor temperature monitor - The sensor is usually located at one position only. It is known that the temperature varies along the span as well as between spans. To make a judgment on this one reading only is risky since the temperature of the conductor can be very different from span to span, especially if the line changes direction or terrain (sheltered or unsheltered spans). The sensor could be placed in a span that has the wind perpendicular to it. An adjacent span could have altered the line direction so that the line is now parallel to the wind. The cooling is approximately 40 % in the line section parallel to the wind compared to the section perpendicular to the wind. This means that the section parallel to the wind, the section without the sensor, is hotter than the span with the sensor by a considerable amount. The sensor may therefore indicate that the line is under the thermal limit when in effect it could be above the limit. The temperature measured is the conductor surface temperature and not the average conductor temperature (that affects sag). Direct Clearance Determination with Sag-Tension Monitors Sag measurements in a single span or in a few adjacent spans can be monitored either optically or by using commercial laser survey instruments mounted at a distance from the line. EPRI has developed a “video sagometer” which uses existing laser surveying technology with automatic target recognition and target tracking, to monitor the conductor sag. One or more reflectors are 8-6
attached at various locations on the conductor and/or conductor support points and the "x, y, z" co-ordinates are determined by measuring the distance and angles from a known point. The measuring instrument can take measurements at preset intervals or on demand. Software has been developed to calculate the clearance to the ground or other objects. The sagometer can be used with or without daylight. Sag monitors offer several advantages. If the targets can be mounted on the energized conductor with a hot stick, they can be installed without the need to take a line outage. They are also clearly the most accurate method of determining the sag and ground clearance in the span where they are mounted. Over the last 5 years, use of line tension monitors is wide spread within the US. The first commercially available device, known as the CAT-1, is installed at over 30 utilities. There are a number of reasons for the popularity of these devices. The tension-measuring device is a commercial load cell, which appears to be very reliable and exhibits little drift with varying weather and line load conditions. The device is mounted on the grounded side of a dead-end insulator string and thus is not subject to high electric fields. Line tension monitors are normally installed with the line taken out of service. While the sag in the last span can be determined with great accuracy, the sag estimate for other spans in the line section may exhibit increasing error. The estimation of sag in spans away from the monitoring location is prone to certain errors whether the sag or tension monitor is used. In either case, if the line section has nearly equal span lengths, long insulator suspension strings, and modest temperature variations, then the sag in remote spans may be calculated simply by using the “ruling span” approximation. The “ruling span” approximation assumes that all spans have the same tension at any temperature. In lines with post insulators, unequal spans, and large temperature variations, the line section needs to be modeled with a more sophisticated line model such as the one described in the IEEE ruling span paper. Either type of monitor provides a direct measurement of the sag-tension behavior of the line at high temperature levels.
Field Test Results EPRI sponsored a series of field tests of dynamic rating and monitoring techniques at four utility sites. Weather and line tension monitors were used. The outcome of these field tests were significant, and EPRI refined both its DTCR circuit rating software and learned certain fundamental facts about how weather affects the rating of overhead transmission lines and how dynamic rating methods are best applied. 1. Dynamic thermal ratings for overhead lines may be calculated based on either real time weather or real time tension data. For weather-based ratings, the wind angle should be assumed fixed and near parallel to the line direction to account for directional variation along the line section.
8-7
2. In rating longer lines with multiple ruling span sections, it is likely that the line rating (dynamic or static) decreases with line length and that dynamic rating of lines requires multiple monitoring locations, and the minimum number of monitors required must be based on field measurements. 3. Tension monitors work well in lines having high current density (greater than approximately 1 amp/mm2) where they generally yield more accurate ratings than single-point weather monitors. However, in lines with low current density (less than 0.5 amps/mm2), weatherbased dynamic ratings are more accurate than those based on sag-tension monitors 4. Tension monitoring allows one to directly measure tension at high temperatures. Weather monitoring does not. Errors in the calculation of high temperature sag using various standard methods can be detected with tension monitors but not with weather monitoring methods. For example, the data obtained in these field tests show that there is a great deal of fluctuation in both wind speed and direction along most line routes, particularly during periods of low wind activity. The following figure shows 15 minute average wind speeds at locations only 1.5 km apart along a line route in Philadelphia.
25 july_15min.xls
Loc #2 (ft/s)
20
15
10
5 Loc #1 has more low wind speeds. 0 0
5
10
15
20
25
Loc #1 (ft/s) Figure 8-2 Wind Speed (15 min average) at Two Locations 1.5 km Apart Along a 230-kV Line in the Eastern US.
8-8
The field tests confirm that not only the wind speed but also the wind direction varies along the line. This raises questions about the usefulness and accuracy of basing dynamic thermal line ratings on weather data from a single location within a line section. It would seem to imply that multiple weather monitor locations might be required within long line sections. Comparison of Weather Monitor and Tension Monitor-Based Dynamic Line Ratings Weather-based real time ratings require real time measurement of wind speed, wind direction, air temperature, solar heating (Ts), and line current. These data may be obtained with a high quality weather station at minimal cost (less than $5,000 US not including labor or necessary communications links). The main advantages of using weather-based line ratings are two-fold: 1. The rating calculation is independent of the line current. 2. The monitoring equipment is modest in cost and portable, not requiring line outages to install. 3. Weather data may also be used to dynamically rate nearby substation equipment. The disadvantages are that the anemometers are quite fragile and prone to measurement error unless calibrated frequently and, being a measurement of weather conditions at a single location, more than one monitoring location may be required for long line sections. Field experiments conducted by Chisholm at Ontario Hydro [10] indicated considerable success in estimating average conductor temperature. The instruments were placed over a five span ruling span section, and the data was based on real time line current and on weather monitors placed at a distance from the line, and it was assumed that the wind angle was fixed at an angle of 20 to 30 degrees. Our comparisons of weather-based and tension-based line ratings at three of the four field-test sites indicates that there is good agreement between minimum values of weather-based and line tension-based ratings when using a fixed wind angle of 22 degrees relative to the conductor axis. This is illustrated in Figure . Based on such observations at each field test site, it appears that weather-based ratings based on a fixed line angle of the order of 20 degrees are conservative under nearly all conditions and that such “weather-based” ratings can be used as a means of warning the operator during periods of “low rating” conditions. When combined with the use of less conservative fixed ratings for planning and low load operation, this weather-based dynamic rating method would be very cost effective.
8-9
Probability less than x axis
100 90
9/19-10/6/97 2 x R ail ACS R 75C max cdr temp
80
Both ratings meas ured s olar temperature.
70 60 Weather-bas ed rating as s uming 22 deg wind angle.
50 40
T ens ion-bas ed rating for E -W line s ection.
30 20
S ummer Normal Line R ating: 1820 amps
10
s ep_mat.xls
3700
3300
2900
2500
2100
1700
1300
0
Normal Rating (amps) Figure 8-3 Comparison of Weather-Based and Tension-Based Cumulative Rating Distributions
4000
I 1 (N-S) I 2 (E-W)
3500
240
9/30 - 10/1/97 2xR ail, T max=75 C
I 3 (N-S)
220 200
I 4 (N-S)
3000
160
amps
2500
140
2000
120 100
1500
bundle current
80
1000
60 40
500
solar temp
wind speed
20
0 1:09
23:09
21:09
19:09
17:09
15:09
13:09
11:09
9:09
7:09
5:09
0
s ep_ mat.xls
Figure 8-4 Comparison of Tension-Based Rating Estimates for Four Separate Line Sections
8-10
ft/s and deg C
180
Rating Variation in Adjacent Line Sections Figure shows the variation in tension-based line rating with time for the 230 -kV SRP line. Four ruling span sections are monitored. I2 is E-W, and the other three are oriented nearly N-S. Note that the E-W span generally has the lowest rating but that this is not true for certain periods such as the three hours starting at 6 AM. Clearly, if the entire line were rated on the basis of a monitor in only one section, the rating would be too high some percentage of the time and therefore not conservative. Multiple monitoring locations are required to correctly calculate the real time line rating; however, it appears that there is good agreement for the three line sections oriented in the same direction (NS). It appears that the number of monitoring locations (either weather or tension) required to calculate the real time line rating correctly must be empirically determined for each location.
8-11
9 REDCONDUCTORING WITHOUT STRUCTURAL MODIFICATIONS TW The use of trapezoidal (TW) aluminum wires in place of round wires potentially increases the cross sectional area of a round wire conductor of the same diameter by approximately 20%. Therefore, the use of TW conductor in uprating offers a reduction in conductor resistance of 20% with no increase in structure transverse loading.
ACSS Aluminum Conductor Steel Supported (ACSS) is described in ASTM B 856-95. It consists of fully annealed strands of aluminum (1350-H0) stranded around stranded steel core. The steel core wires may be aluminized, galvanized, or aluminum clad and are normally “high strength” having a tensile strength about 10% greater than standard steel core wire. In appearance, ACSS conductors are essentially identical to standard ACSR conductors. By using annealed aluminum, the rated strength of ACSS is reduced by an amount dependent on the stranding (e.g. 35% for 45/7, 18% for 26/7, and 10% for 30/7). In fact, a 45/7 ACSS conductor has about the same rated breaking strength as a conventional all-aluminum conductor (e.g. 16,700 lbs for 954kcmil 45/7 ACSS versus 16,400 lbs for 954 kcmil 37 strand AAC (Magnolia)). The thermal elongation coefficient, creep rate, and maximum operating temperature is, however, quite different. ACSS Conductor Designs ACSS is typically available in three different designs: “Standard Round Strand ACSS”, “Trapezoidal Wire of Equal Area”, and “Trapezoidal Wire of Equal Diameter”. In addition, it is possible to obtain all three ACSS conductor designs with any of the standard types of steel core wire (galvanized, aluminized, and alumoweld). Advantages & Disadvantages of ACSS ACSS provides a number of advantages in reconductoring the combined effect of which makes it economically attractive. It has higher self-damping than conventional ACSR. It has lower thermal elongation over a wide range of conductor temperatures. It can be operated at temperatures as high as 250 °C without damage. It can be installed at a higher % rated breaking strength. With reference to the preceding discussion of sag clearance, the conductor properties make it attractive for re-conductoring applications as well as certain new line designs.
9-1
Table 9-1 ACSS Equivalents to Standard Type 16, 795 kcmil, 26/7 ACSR (Drake) Conductor Name
OD (inches)
(mm)
Alum Area (kcmil)
AC Resistance (Ω Ω/mile) (Ω Ω/km)
Drake ACSR
1.108
28.14
795
0.1170
0.0727
Drake/ACSS
1.108
28.14
795
0.1137
0.0707
-3%
Suwannee/ACSS/T W
1.108
28.14
960
0.0939
0.0584
-17%
Drake/ACSS/TW
1.010
25.65
795
0.1132
0.0704
-3%
(∆ ∆%)
In re-conductoring existing lines, in comparison to conventional ACSR conductors, ACSS can yield a much larger increase in thermal capacity while minimizing the need for expensive structure modifications. In new lines, this conductor can yield designs with less environmental impact (shorter and/or fewer structures) with greatly increased thermal capacity for essentially no increase in cost. As discussed in the following, the key advantages of ACSS are: •
Operate to 250 °C with no loss in strength.
•
No creep elongation over time.
•
High self-damping (which yields low levels of Aeolian vibration).
•
Lower thermal elongation than conventional conductor
•
63% IACS conductivity, not 61.2%
•
Equal OD & equal AREA options
Higher Maximum Temperature Typically aluminum stranded conductors can be operated at temperatures up to 95 °C without significant loss of tensile strength. Aluminum conductors with a steel-reinforcing core can be operated at temperatures of up to 150 ° C for limited periods. Because the aluminum in ACSS is fully annealed at the factory, it can be operated continuously at temperatures up to 250 °C or, with special high temperature tolerant galvanizing coatings such as "Galfan", even higher. The following table shows a comparison of continuous conductor ampacity (with 2 ft/sec crosswind, 40 °C air temperature, and full sun) for ACSS and ACSR conductors. Note that the ampacity of an ACSS conductor operating at 250 °C is nearly twice that of an ACSR of the same cross sectional area operating at 100 °C.
9-2
Table 9-2 Continuous Ampacity of Equivalent ACSR and ACSS Conductors as a Function of Maximum Allowable Conductor Temperature Conductor o Temperature ( C)
Drake ACSR*
Suwannee ACSS/TW
Drake/ACSS or Drake/ACSS/TW
75
730
820
720
100
990
1110
980
150
1490
1320
200
1770
1560
250
2000
1740
o
*For continuous loads, ACSR is normally limited to about 100 C to avoid annealing of the aluminum strands.
Thermal Elongation Aluminum strands elongate thermally at twice the rate of steel. The sag increase of ACSR conductor is therefore less than it is for AAC. In the case of ACSS, the tension level in the aluminum strands is very small and the conductor elongates thermally as though it were steel. Thus, the sag increase in going from 15 °C to 150 °C with ACSS may be the same as the sag increase from 15 °C to 95 °C with ordinary ACSR. As an example of this lower thermal elongation of ACSS, consider the data in Table 9-3. The ACSS conductor has the same sag at 150 °C as the ACSR conductor of the same diameter has at 100 °C. Therefore, for a clearance-limited line, by re-conductoring with ACSS, the thermal capacity of the line increases by about 30% without the need to raise or reinforce structures. Table 9-3 Illustration of the Lower Thermal Elongation of ACSS Conductor. Conductor Temp o
Sag of Drake ACSR
Sag of Drake/ACSS
Ampacity
( C)
(ft)
(m)
(ft)
(m)
(Amperes)
15
31.0
9.4
31.0
9.4
100
37.6
11.5
35.3
10.8
1110
150
37.8
11.5
1490
Self-Damping The tension of conductors in overhead lines is normally determined by concern about Aeolian vibration induced fatigue. It is normal to limit initial tension to no more than 20% of the rated breaking strength in order to limit vibration levels. Because it has higher self-damping than ordinary ACSR, ACSS may be installed to smaller initial sags and because it has a lower modulus, it yields lower maximum tensions than ACSR.
9-3
Low Creep Elongation When re-conductoring one must allow for creep elongation over time with ordinary ACSR. In addition, except for ACSR conductors with a high steel content, one must consider the possibility of accelerated creep at high operating temperatures. ACSS does not creep at any temperature, high or low. Thus, its final and initial sags are the same as shown in Figure 9-1.
Initial Sag @15C
Final Sag @15C
Final Sag @150C
Minimum Ground Clearance
Figure 9-1 Illustration of Typical Behavior of ACSS Conductor Illustrating that Initial and Final Sags are Nearly Identical
Not only is there little or no difference between the initial and final sag, but also the initial sag is less and the change in sag due to temperature is less than it is for standard ACSR. New Line Application of ACSS ACSS was originally developed for use in re-conductoring existing lines. Recent interest in maximizing utilization of transmission assets has made this conductor more favorable in certain new line design applications. Consider Figure 9-2, which illustrates how the higher allowable temperature of ACSS, the reduced diameter of TW aluminum wires, and the lower elastic modulus of ACSS combine to allow a 30% increase in thermal capacity without a change in the maximum tension load on structures for a new line design. The right-hand axis is sag measured in feet.
9-4
1400
50
1200
45
1000
40
800
35
600
30
400 200
25
0
20 75
100
125
150
175
200
225
Sag - ft
AMPACITY
Max Tension of Drake/ACSS/TW same as Standard Drake ACSR
250
CDR TEMP - DEG C
STD DRAKE
DRAKE/ACSS/TW
STD DRAKE
DRAKE/ACSS/TW[1]
Figure 9-2 Application of ACSS in New Line Design Showing 30% Higher Thermal Rating with the Same Maximum Sag and Tension Loading on Structures.
In comparison to standard ACSR or other types of conventional conductors, a new line can be built with ACSS at a much lower cost per MVA of thermal capacity. This is because the conductor can be operated at much higher temperatures for the same sag and structure loading. This is particularly true of ACSS/TW conductor. The novel characteristics of ACSS make it attractive as a replacement conductor for HV lines where thermal capacity is inadequate. ACSS can be substituted for existing ACSR of the same diameter. Although having nearly the same resistance and diameter as the conductor it replaces, ACSS can be operated at a much higher temperature without exceeding the original high temperature sag levels. Since the aluminum strands of ACSS are fully annealed, it has a somewhat lower rated strength than the same stranding in ACSR. In areas where ice and wind loads permit, ACSS may be specified with a reduced steel content. The result is that with ACSS the maximum tension loads on angle and dead-end structures may be no higher than those generated by the ACSR conductor it replaces. As an example of the advantages of ACSS in re-conductoring, consider Figure , which shows ampacity and sag as a function of maximum allowable temperature. The original conductor in the existing line is assumed to be 477 kcmil ACSR (Hawk). The proposed replacement conductors are 565.3 kcmil ACSS/TW (Calumet), which has the same diameter as the original and 795 kcmil ACSR (Drake), which has a diameter that is 30% higher. For continuous operation, the 565.3 kcmil ACSS/TW (Calumet) conductor at 200 °C has an ampacity about 25% 9-5
higher than Drake at 100 °C and lower maximum sag than the original or replacement ACSR conductors.
Increase Ampacity to 1200 amps by reconductoring with Drake or Calumet/ACSS/TW 1400
24.0 22.0
1000
20.0
800
18.0
600
16.0
400
14.0
200
12.0
0
10.0 75
100
125
150
175
SAG - FT
AMPACITY
1200
200
CDR TEMP - DEG C HAWK
Calumet/ACSS/TW
DRAKE
HAWK
Calumet/ACSS/TW
DRAKE
Figure 9-3 Ampacity and Sag of Original Drake ACSR and Calumet ACSS/TW Replacement Conductor as a Function of Maximum Allowable Temperature.
High Temperature Aluminum Alloy Conductors The various Japanese manufacturers (e.g. Fujikura Ltd., Sumitomo Electric Industries, Ltd.) have developed a whole range of special high temperature conductors. These conductors consist of special temperature tolerant aluminum alloy wires combined with ordinary steel or a special low thermal elongation steel wire called “Invar”. The acronyms for these conductors indicate the type of aluminum alloy (TAC, GTA, UTA, XTA, and ZTA); the type of steel core wire (SR or IR), and whether the aluminum strands are trapezoidal and there is a gap between the inner layer of aluminum and the steel core (e.g. GACSR or GTACIR). A partial list of the most common types includes the following names: TACSR, GTACSR; UTACSR, GTACSR, UTACIR, XTACSR, XTACIR, ZTACSR, and ZTACIR. The acronyms refer to the type of high temperature alloy, whether the conductor is “gapped”, and to the type of steel core material. As a simple comparison, consider Table 9-4, a summary of the maximum operating temperatures of the various Japanese heat resistant conductors.
9-6
Table 9-4 Maximum Operating Temperatures for High Temperature Alloys Made in Japan. Description
Symbol
Max Temp Continuous
Max Temp Emergency
Super Heat Resistant
UTACSR
200
230
Super Heat Resistant
ZTACSR
210
240
Super Heat Resistant
XTACSR
230
310
Heat Resistant
TACSR
150
180
Normal
ACSR
95
125
High Temperature Alloys of Aluminum The following table is a description of the heat resistant alloys of aluminum: Table 9-5 Conductivity of High Temperature Alloys Made in Japan. Aluminum Alloy
%Conductivity
Max Temp Continuous
Min. Tensile Strength
(IACS)
(°°C)
(kgf/mm )
57.0 60.0 58.0 60.0 61.0
200 210 230 150 95
16.2to17.9 16.2to17.9 16.2to17.9 16.2to17.9 16.2to17.9
UTAL ZTAL XTAL TAL 1350-H19
2
The TAL alloy was developed in the 1960’s. The other alloys were developed in a continuing attempt to keep the conductivity near that of ordinary electrical conductor grade aluminum (1350-H19). The relationship between conductivity and maximum continuous temperature is shown in the following figures. Special Invar Steel Core ACSR conductors are manufactured with a variety of steel wire coatings to prevent corrosion. Normal steel core wire has a tensile strength of 170 to 190 ksi (1170 to 1310 MPa or 120 to 130 kgf/mm2). Invar steel wires have a 15-20% lower tensile strength but also have a much lower coefficient of thermal expansion than conventional galvanized steel wire. The thermal expansion coefficient of conventional steel is 11.5 × 10-6 per degree C whereas the thermal coefficient of Invar steel is only 2.8 × 10-6 per degree C. At high operating temperatures, the aluminum strands of any high temperature conductor unloads tension almost entirely to the steel core. With Invar, this happens at a lower (“knee
9-7
point”) temperature. In addition, the rate of increase in sag with further increases in conductor temperature is less with Invar steel cores. This is demonstrated in Figure 9-5:
Figure 9-4 Plots of Conductivity and Loss of Strength for High Temperature Japanese Aluminum Alloys
9-8
Figure 9-5 Comparison of ACSR-type Conductors with Invar and Conventional Steel Cores.
Gapped Construction The lower temperature range aluminum alloys are optionally supplied in a “gapped” construction as shown in the following picture taken from a Sumitomo Technical Data Sheet:
Figure 9-6
9-9
Summary Table Showing Gapped and Conventional constructions for Japanese High Temperature Conductors.
In the gapped construction, the space between the steel core and the inner layer of the aluminum alloy strands is filled with high temperature grease to prevent corrosion. In addition, the gapped construction conductors are installed with full tension on the steel core (and little or no load on the aluminum strands). It was noted in the preceding comparison of Invar with conventional steel wire that Invar has a reduced tensile strength. While it is conceivable that a gapped construction conductor could be made with an Invar steel core for use in a light-loading region such as Arizona, it is not commonly done in Japan where heavy ice and wind loads commonly occur. Thus, as shown in the Figure, Gapped conductors are designed with conventional high strength steel core wires. Comparing ACSS and High Temperature Alloy Conductors The major advantage of using ACSS is its cost (typically sold at a premium of less than 15%) and it’s wide availability outside of Japan. Also, ACSS has been used extensively and most of the handling and installation difficulties are well understood. The major advantage of the High Temperature Alloy conductors is that they can be used in regions experiencing heavy ice and wind loads, (ACSS cannot) and they are applicable to EHV lines where surface roughness of ACSS may yield higher corona noise and radio noise levels. The cost of these conductors, however, appears to be relatively high (probably a premium in excess of 50% over conventional ACSR). The availability of these high temperature alloy conductors outside of Japan is uncertain at this point and shipping costs would simply worsen the cost issue.
9-10
10 UPRATING CASE STUDIES Clearly, the uprating method applicable to a particular line depends on a number of different parameters, which must be defined as part of the uprating process. There are, however, certain aspects of the line design that suggest certain uprating methods or that suggest avoiding certain approaches. This section of the guide includes a collection of typical candidate lines with appropriate line uprating methods identified (including references to the section describing the method). To be useful, a detailed description of each case study is included to make at least some initial decisions about what approach to take, but a detailed plan profile or sag survey data is not included. Similarly, the lines include voltage ranges of69-kV to 345-kV , the most common lines that need uprating. Some of the examples may have been uprated previously.
Case Study #1 – 69-kV, Copper Conductor, Short Spans, 50% Rating Increase Typical of the oldest lines in many systems, the desired increase in thermal line rating results from an attempt to deal with a relatively rare single contingency that would persist for up to 24 hours. The addition of a new 345 -kV line section will remove the contingency within 5 years. Line Description •
69-kV system voltage, 4 suspension insulator bells, ferrous clamps.
•
No dampers, bolted dead-ends, no armor rod.
•
7 strand, #2/0 AWG Copper conductor, original splices.
•
Rating conditions – 2ft/sec perpendicular, 40 °C air, sun, 50 °C continuous/75 °C emergency.
•
Mild corrosion area, broken strands found at several clamp locations.
•
Normal daily peak annual loading is only 30% of normal continuous rating. System analysis by planning needs a 50% increase in emergency rating (post-contingency loading).
•
Span lengths range from 250 to 400 ft. Ruling span is 350 ft. Electrical clearance at 75 °C ranges from 2ft to 10ft. Average clearance is 4 ft. The line length is 10 km (6 miles) with 15 line sections going in a predominantly east-west direction.
•
NESC Medium loading area (0.25in ice with 4 psf wind). Everyday tension at 15 °C equal to 12% RBS (Rated Breaking Strength) final.
•
Wood pole H-frame structures, no knee or X bracing.
10-1
•
Built in 1935, 20% damaged poles (rot) replaced in 1962. Another 15% replaced in 1988. No extensive structural failures known. No broken conductors.
Uprating Analysis Given the age of the phase conductor, the evidence of some obvious vibration fatigue damage, the original splices, and its rare operation at high temperature levels, the re-rating of this line by going to a higher maximum temperature is risky. On the other hand, the line’s electrical clearance margins are relatively generous, the rating weather conditions are conservative, and the contingency loading event is relatively rare and of limited duration. The following parameters make this line a good candidate for reconductoring: it has a low normal load, and the poles are in a relatively good condition. The low normal load implies that the line can be taken out of service for construction. The relatively good condition of the poles can have bracing added to them, if required. Reconductoring with a larger diameter trapezoidal strand conventional aluminum or ACSR conductor is possible.
Case Study #2 – 69-kV, ACSR Conductor, Short Spans, 30% Rating Increase Typical of the oldest lines in many systems, the desired increase in thermal line rating results from an attempt to deal with a relatively common seasonal peak load resulting from peak demand sales. The peak demand sales are from merchant plants that are newly added to the existing system. The periods of high electrical loading may persist for weeks during periods of peak demand. Line Description •
69-kV system voltage, 4 suspension insulator bells, aluminum clamps.
•
Dampers on exposed sections, compression dead-ends, armor rod used at all clamps.
•
26/7 strand, 366.4 kcmil, ACSR conductor, approximately 20% of full tension splices replaced on basis of infrared scans.
•
Rating conditions – 2ft/sec perpendicular, 40 °C air, sun, 75 °C continuous/90 °C emergency.
•
Mild corrosion area, no broken strands found in routine climbing inspection.
•
Normal daily peak annual loading is 70% of normal continuous rating. System analysis by planning indicates that the continuous rating needs 30% increase to meet peak seasonal demand. Emergency loading will be equal to peak seasonal normal.
•
Span lengths range from 250 to 400 ft. Ruling span is 350 ft. Electrical clearance at 75 °C ranges from 2ft to 10ft. Average clearance is 4 ft. The line length is 10 km (6 miles) with 15 line sections going in a predominantly east-west direction.
10-2
•
NESC Heavy loading area (0.5in ice with 4 psf wind and 1.0 inch radial ice). Everyday tension at 15 °C equal to 14% RBS (Rated Breaking Strength) final.
•
Wood pole H-frame structures, knee but no X bracing.
•
Built in 1948, 10% damaged poles (rot) replaced in 1969. Another 20% replaced in 1985. One line section failure in 1972 due to excessive ice load. Cross arm broken, not conductor.
Uprating Analysis Given the regular inspections of the line, the existing protection from vibration fatigue damage, the inspection and replacement of compression splices, and the extensive experience in operating this line at conductor temperatures well above air temperature, the re-rating of this line by going to a higher maximum temperature is a viable option. On the other hand, the line’s electrical clearance margins are relatively generous, the rating weather conditions are conservative, and the contingency loading event is relatively rare and of limited duration. The following parameters make this line a good candidate for reconductoring: it has a low normal load, and the poles are in a relatively good condition. The low normal load implies that the line can be taken out of service for construction. The relatively good condition of the poles can have bracing added as required. Reconductoring, perhaps with a larger diameter trapezoidal strand conventional aluminum or ACSR conductor is possible.
Case Study #3 – 230-kV, 795kcmil ACSR, Medium Spans, Steel Lattice, 10% Rating Increase Typical of the moderate aged lines in many systems, this double circuit 230 -kV line was built in the 1960’s using steel lattice self-supporting structures. The desired increase in thermal line capacity results from an attempt to deal with a relatively common post-contingency emergency load condition where the operator can re-dispatch generation to reduce the line load in about one hour, with little economic penalty. Load shedding is also an option in case of overload but is undesirable from a public relations viewpoint. The period of high loading is likely to persist for several weeks if it occurs. Line Description •
230-kV system voltage, double circuit, 12 suspension insulator bells, aluminum clamps.
•
Dampers on exposed sections, compression dead-ends, armor rod used at all clamps.
•
30/19 strands, 795 kcmil ACSR conductor, the condition of full tension splices is uncertain.
•
Rating conditions – 3ft/sec perpendicular, 30 °C air, sun, 100 °C continuous/100 °C emergency
10-3
•
Mild corrosion area, no broken strands found in routine climbing inspection.
•
Normal daily peak annual loading is 40% of normal continuous rating. System analysis by planning indicates that the emergency rating needs a 10% increase to meet the peak post-contingency loading. System re-dispatch is possible in one hour.
•
Span lengths range from 800 to 1100 ft. Ruling span is 1000 ft. Electrical clearance at 100 °C ranges from 1ft to 3ft. Average clearance at 100 °C is 2 ft. The line length is 40 km (24 miles) with 20 line sections going in a predominantly north-south direction.
•
NESC Heavy loading area (0.5in ice with 4 psf wind and 1.0 inch radial ice). Everyday tension at 15 °C equal to 18% RBS (Rated Breaking Strength) final.
•
Steel lattice, self-supporting structures. Galvanizing is in good shape. Concrete footing inspection indicates they are in “near-original” condition.
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Built in 1963, structures have been inspected by helicopter. No major line failures have occurred. One line section failure in 1972 due to a crane accident. Cross arm failure and conductor damaged.
Uprating Analysis Clearly, this line is in reasonably good condition with modest maintenance costs and the required incremental uprating is relatively small, hence reconductoring would yield little or no savings in losses or maintenance. C o s t C o m p a ris o n o f U p ra tin g O p tio n s 45 B undle
Co st o f M e th o d (%N e w L in e )
40 A CS S
35 30 25 20 15 DTR
10 5 0 0
10
20
30
40
50
60
70
% In cre a se in Ra tin g
Figure 10-1 5 year Total Cost vs. Percent Increase in Rating for Case Study #3.
10-4
80
90
100
Given the regular inspections of the line, the existing protection from vibration fatigue damage, the inspection and replacement of compression splices, and the extensive experience in operating this line at conductor temperatures well above air temperature, the re-rating of this line by going to a higher maximum temperature is an option. On the other hand, the line’s electrical clearance margins are relatively generous, the rating weather conditions are conservative, and the contingency loading event is relatively rare and of limited duration. The following parameters make this line a good candidate for reconductoring: it has a low normal load, and the poles are in a relatively good condition. The low normal load implies that the line can be taken out of service for construction. The relatively good condition of the poles can have bracing added as required. Reconductoring, perhaps with a larger diameter trapezoidal strand conventional aluminum or ACSR conductor is possible.
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11 REFERENCES Power Flow Limits for Overhead Lines 1. 1979 Annual Electric Power Survey. New York: Edison Electric Institute. 2. EHV Transmission Line Reference Book. New York: Edison Electric Institute, 1968. 3. Transmission Line Reference Book: 345-kV and Above, Palo Alto, Ca, Electric Power Research Institute, 1975. 4. Transmission Line Reference Book: HVDC to 600-kV. Palo Alto, Ca, Electric Power Research Institute. 5. S.B. Crary Power System Stability, Vol. I, New York, John Wiley and Sons, 1945. 6. H.P. St. Clair, Practical Concepts in Capability and Performance of Transmission Lines, AlEE Transactions Power Apparatus and Systems, Paper 53-338, presented at the AlEE Pacific General Meeting, Vancouver, B.C., Canada, September 1-4, 1953. 7. R.D. Dunlop, R. Gutman, P.P. Marchenko, Analytical Development of Loadability Characteristics for EHV and UHV Transmission Lines, IEEE Transactions on Power Apparatus and Systems, Vol. PAS98, pp. 606-617, March/April 1979.
Transmission Line Design 1. National Electric Safety Code, 1997 Edition, C2-1997. 2. Relationships of National Electrical Safety Code Vertical Clearances and Potentially Conflicting Activity, Clapp, Allen L., IEEE Transactions on Power Apparatus and Systems, Vol. PAS-104, No. 11, November 1985, pp. 3306-3312. 3. REA Bulletin 1724E-200, Design Manual for High Voltage Transmission Lines, Rural Electrification Administration, 9/3/92. 4. Douglass, Dale A., Economic Measures of Characteristics, IEEE Paper 86 TD 502-9 PWRD.
Bare
Overhead
Conductor
5. Kennon, Richard E., and Douglass, Dale A., EHV Transmission Line Design Opportunities for Cost Reduction, IEEE Paper 89 TD 434-2 PWRD.
Thermal Rating of Lines 1. Douglass, Dale A., and Rathbun, L.S., AC Resistance of ACSR - Magnetic and temperature effects, IEEE Paper 84 SM 700-1. 2. American Society for Testing and Materials (ASTM), 1991 Annual Book of ASTM Standards - Section 2, Nonferrous Metal Products, Volume 02.03, Electrical conductors, Including B-1 Standards.
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3. Kennelly, A.E., Laws, F.A., and Pierce, P.H., Experimental Researches of Skin Effect in Conductors, AIEE Transactions, Vol. 34, Part 2, 1915, pp. 1953-2021. 4. Wright, H.B., Skin Effect in Tubular and Flat Conductors. 5. Lewis, W.A., and Tuttle, P.D., The Resistance and Reactance of Aluminum Conductors Steel Reinforced, AIEE Transactions, Vol. 77, Part III, 1958. 6. Aluminum Association, Aluminum Electrical Conductor Handbook, Third Edition, 1989. 7. IEEE, IEEE Standard for Calculating the Current-Temperature Relationship of Bare Overhead Conductors, PES, IEEE Standard 738-1993. 8. House, H.E., and Tuttle, P.D., Current-Carrying Capacity of ACSR. 9. IEEE Standard 738-93, IEEE Standard for Calculation of Bare Overhead Conductor Temperature and Ampacity, Published 1993. 10. CIGRE WG 05 - Conductors, The Thermal Behaviour of Overhead Conductors, 2281 (WG05), December, 1981. 11. Black, W. Z. and Rehberg, R. L., Simplified model for steady state and real-time ampacity of overhead conductors, IEEE Transactions on Power Apparatus and Systems, vol. 104, Oct. 1985, pp 29-42. 12. Davidson, G. A., et al., Short-time thermal ratings for bare overhead conductors, IEEE Transactions on Power Apparatus and Systems, vol. PAS-88, No.3, Mar. 1969. 13. House, H. E., Rigdon, W. S., Grosh, R. J., and Cottingham, W. B., Emissivity of Weathered Conductors after Service in Rural and Industrial Environments, AIEE Transactions, pp. 891-896, Feb. 1963 14. Morgan, V. T., The Current carrying capacities of overhead line conductors. Paper A75 575-3, IEEE/PES Summer Meeting, Los Angeles, CA, 1978. 15. Schurig, O. R. and Frick, C. U. Heating and Current Carrying Capacity of Bare Conductor for Outdoor Service. General Electric Review, vol. 33, no. 3, pp. 141-157, Mar. 1930. 16. Transmission Conductors Thermal Ratings, Paper 68-TAP-28, Report by Transmission Advisory Panel, East Central Area Reliability Coordination Agreement.
High Temperature Effects - Conductor 1. Barrett, J.S., Ralston, P. And Nigol, O., Mechanical Behaviour of ACSR Conductors, CIGRE International Conference on Large High Voltage Electric Systems, September 1-9, 1982. 2. Rawlins, Charles B. Some Effects of Mill Practice on the Stress Strain Behavior of ACSR, presented at IEEE Winter Meeting, Tampa, FL, February, 1998. 3. Chisholm, W.A., Ampacity Field Studies On Line With Low Operating Temperature, EPRI DTR Seminar, May, 1986. 4. Harvey, JR. Creep of Transmission Line Conductors. IEEE Trans., Vol. PAS-88, No. 4, pp. 281-285, April 1969 11-2
5. Harvey, JR and Larson, RE. Creep Equations of Conductors for Sag-Tension Calculations. IEEE Paper C72 190-2 6. Harvey, JR and Larson RE. Use of Elevated Temperature Creep Data in Sag-Tension Calculations. IEEE Trans., Vol. PAS-89, No. 3, pp. 380-386, March 1970
High Temperature Effects - Connectors 1. Aronstein, J Conduction in Failing Aluminum Connections Proceedings of the Thirty-Sixth IEEE Holm Conference on Electrical Contacts Montreal, Quebec August 1990 2. Bennett, EH Designing Compression Fittings for Long-Term Survival, Bonneville Power Engineering Symposium, April 1992 3. Braunovic, M, Effect of Contact Aid Compounds on the Performance of Bolted Aluminum-to-Aluminum Joints Under Current Cycling Conditions, 31st Annual Holm Conference, Chicago IL, September 1985 4. Dalle, B. Size and Aging of Joints for Bare Conductors of Overhead Line, Electricite de France, December 1982. 5. DeLuca, CB, Current Cycling Connectors in Tension, Proceedings of Seminar on Effects of Elevated Temperature Operation on Overhead Conductors and Accessories, pp. 110-119, Atlanta, Georgia, May 1986 6. Dupre, H. The Problems Involved in Designing Connectors for Aluminum Cable. AIEE 51-325, September 1951 7. Frank, W, The Critical Aspects of Steel Hardware in Aluminum Connectors, AIEE Transmission and Distribution Committee, June 1959 8. Howitt, WB, Elevated Temperature Performance of Conductor Accessories, Proceedings of Seminar on Effects of Elevated Temperature Operation on Overhead Conductors and Accessories, pp. 120-139 Atlanta, Georgia, May 1986 9. Naybour, R.D. and Farrell,T. Degradation Mechanisms of Mechanical Connectors on Aluminum Conductors. PROC IEE, Vol. 120, No. 2, pp. 273-280, February 1973 10. Reding, JL, Investigation of Thrasher Compression Fittings on BPA's Direct Current Transmission Line IEEE Trans., PWRD-6, No. 4, pp. 1616-1622, October 1991 11. Standard, EEOI-NEMA. Connectors for use Between Aluminum or AluminumCopper Overhead Conductors. NEMA Pub. No. CC 3-1973, August 1973.
High Temperature Effects - Hardware 1. Adams, HW, Thermal Cycle Tests of SSAC and Associated Fittings, Reynolds Aluminum, Series No. 34, May 1976 2. Bissiri, A., Suspension Clamp Power Loss Tests, Electrical World, Vol. 129, pp. 5862, January 1948
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3. Champa, RJ, Heating Characteristics of the Armor-Grip Suspension at Elevated Temperatures, Preformed Line Products Co Research and Engineering, TR-591-E, November 1976 4. Crabb, VL and Sheadel, JM. Magnetic Heating of Suspension Clamps. Transactions, Vol. 68, pp. 1032-1035, 1949.
AIEE
5. Farley, R.W. Power Losses in Malleable Iron and Aluminum Overhead Line Suspension Clamps. Electrical Review, Vol. 168, No. 15, 1961 6. Morgan, V.T. Non-magnetic Suspension Clamps for Overhead Power Lines,. Electrical Review, Vol. 175, No. 9, pp. 314-317, August 1964 7. Nabet, Guive, Effect of Elevated Temperature on Conductors and Associated Hardware, presented at EEI T&D Baltimore, Maryland, October 1985 8. Ohio Brass, Cooler in the Clamp, Hi-Tension News, p.7, September 1959 9. Olmsted, LM, Joints and Hardware Limit Overhead Conductor Ratings, Electrical World, Vol. 127, pp. 42-45, January 1947
Probabilistic Rating Methods 1. Beers, G.M., et al, Transmission Conductor Ratings, AIEE Transactions, Paper 6386. 2. Hsaio, Wen, San Diego Gas & Electric, Private communication. 3. Reding, J.L., A Method for Determining Probability Based Allowable Current Ratings for BPA’s Transmission Lines, IEEE Transactions on Power Delivery, Vol. 9, No. 1, January, 1994.
Dynamic Rating Methods 1. Black, W.Z. and Byrd, W.R., Real Time Ampacity Model for Overhead Lines, IEEE Transactions, Vol. PAS-102, No. 7, July, 1983, pp. 2289-2293. 2. Black, W.Z., Byrd, W.R., Bush, R.A. and Champion, T.C., Experimental Verification of a Real Time Program for the Determination of Temperature and Sag of Overhead Lines, Paper 83 WM 144-3, January, 1983. 3. Seppa, Tapani, et al. Use of On-Line Tension Monitoring for Real Time Thermal Ratings, Ice Loads, and Other Environmental Effects, CIGRE International Conference on Large High Voltage Electric Systems, September, 1998, Paris, France. 4. Wong, T. Y., Findlay, J. A., and McMurtie, A. N., An On-Line Method for Transmission Ampacity Evaluation, IEEE Transactions on Power Apparatus and Systems, vol. PAS-101, no. 2, Feb. 1982. 5. Foss, S. D., Lin, S. H., and Fernandez, R. A., Dynamic Thermal Line Ratings—Part 1—Dynamic ampacity rating algorithm. IEEE Transactions on Power Apparatus and Systems, vol. PAS-102, no. 6, pp. 1858-1864, June 1983. 6. Davis, M. W., Development of Real Time Thermal Rating System. St. Louis, MO: Edison Electrical Institute T&D, May 19, 1979.
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7. Davis, M. W., A new thermal rating approach: the real time thermal rating system for strategic overhead conductor transmission lines, Part III. IEEE Transactions on Power Apparatus and Systems, vol. PAS-97, pp. 444-455, Mar./Apr. 1978. 8. Davis, M. W., A new thermal rating approach: the real time thermal rating system for strategic overhead conductor transmission lines, Part II. IEEE Transactions on Power Apparatus and Systems, vol. PAS-97, pp. 810-825, Mar./Apr. 1978. 9. Davis, M. W., A new thermal rating approach: the real time thermal rating system for strategic overhead transmission lines, Part IV. IEEE Transactions on Power Apparatus and Systems, vol. PAS-99, pp. 2184-2192, Nov./Dec. 1980.
Reconductoring Lines with Novel Conductors 1. Adams, H.W., Steel Supported Aluminum Conductors (SSAC) for Overhead Transmission Lines, IEEE Paper T 74 054-3, Presented at the IEEE PES Winter Power Meeting, 1974. 2. Douglass, D.A., and Roche, J.B., T2 Wind Motion Resistant Conductor, IEEE Transactions on Power Apparatus and Systems, Vol. PAS-104, No. 10, October 1985. 3. Kirkpatrick, L.A., McCulloch, A.R., and Pue-Gilchrist, A.C., Ten Years of Progress with Self-Damping Conductor, IEEE Paper F 79 736-0, Presented at the IEEE PES Summer Meeting, 1979. 4. Edwards, A.T., and Livingston, A.E., Self-Damping Conductors for the Control of Vibration and Galloping of Transmission Lines, IEEE Paper 68 C 59 PWR. 5.
Ridley’s paper.
Sag-tension Calculations for Overhead Lines 1. Ehrenburg, D.O., Transmission Line Catenary Calculations, AIEE Paper, Committee on Power Transmission & Distribution, July 1935. 2. Winkelman, P.F., Sag-Tension Computations and Field Measurements of Bonneville Power Administration, AIEE Paper 59-900, June 1959. 3. National Electric Safety Code, 1993 Edition. 4. Fink, D.G., and Beaty, H.W., Standard Handbook for Electrical Engineers, 13th Edition, McGraw Hill. 5. Aluminum Company of America, Graphic Method for Sag Tension Calculations for ACSR and Other Conductors. 6. Aluminum Association, Stress-Strain-Creep Curves for Aluminum Overhead Electrical Conductors, Published 7/15/74. 7. Limitations on Stringing and Sagging Conductors, Paper TP64-146, Working Group of the IEEE Towers, Poles, and Conductors Subcommittee of the Transmission and Distribution Committee of the IEEE Power Engineering Society. 8. IEEE Guide to the Installation of Overhead Transmission Line Conductors, IEEE Standard 524-1993, Published by IEEE, New York, NY.
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9. Cahill, T., Development of Low-Creep ACSR Conductor, Wire Journal, July 1973. 10. Overend, P.R., and Smith, S., Impulse Time Method of Sag Measurement.
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