Electrical Transmission and Substation Structures 2009: Technology for the Next Generation

This paper follows the evolution of wood pole design over the last 80 years and an example is used to demonstrate how the relative safety factor has increased. A brief review of the changes in the National Electrical Safety Code (NESC) strength requirements from 1927 to 2007 is presented to show how little it has changed. Technological advances in calculators, computers and computer software make it possible to analyze complex problems. Equations that were once simplified to facilitate computation are now expanded to include components previously ignored. However, the NESC has not adapted to incorporate these changes, resulting in more conservative designs.

Unlike the statement in our American Declaration of Independence, which declares "all men are created equal", electrical transmission and distribution poles are not necessarily so. Yet as an industry, we continue to work very hard to "commoditize" poles of differing structural attributes and material behaviors and we continue to try to relate them as an "equivalent" to ANSI class wood poles. It is easy to understand why we want to do this as we want to keep things simple, foolproof, less work, and "standardized", etc., etc. etc. But with the industry's inconsistent application of basic structural principles, the practice can sometimes lead to much confusion — at times chaotic confusion. Since the development of the ANSI Standard Classification system for wood poles, a reasonable level of consistency and predictable behavior has been established for a highly variable product — natural wood poles. There is no doubt, that wood poles remain an integral and popular choice for supporting electrical power lines in the United States. But, for a variety of reasons utilities are increasingly specifying and installing non-wood poles of tubular steel, prestressed concrete and fiber reinforced polymer (FRP) materials in place of these wood poles for certain line design reasons. Those reasons are NOT the focus of discussion in this paper. Rather, this paper's discussion is intended to be focused on the potential structural differences that may be experienced when we take a single, quality and dimensional standard for one pole material (natural wood poles), and try to establish "equivalent" structural performance and behavior expectations across a variety of other structural materials. Understanding the performance and structural behavior characteristics of each of the materials is not that difficult. Our consistent specification and communication of desired structural characteristics across all materials is where the confusion seems to be. This paper will attempt to discuss such characteristics as: 1) nominal strength; 2) stiffness; and 3) durability and how they compare across common pole materials. As well, this paper also discusses how the current NESC and various RUS Bulletins deal with the various material strengths, reliability and behaviors.

Overhead transmission lines are designed to withstand meteorological loads such as wind, ice, combined wind and ice and static residual loads due to broken conductor and/or ice shedding. A line could be subjected to dynamic overloading when a triggering event is caused by a component failure. In this situation, a shock wave propagates through the system and a redistribution of the force takes place. If the capacity of the remaining system can not support this force redistribution, the line may experience a cascade failure. This paper presents a systematic methodology to model both the static and dynamic behaviors of a line due to conductor breakage using the ADINA (Automatic Dynamic Incremental Nonlinear Analysis) program. Based on the analysis, the extent of a cascade damage/failure zone is estimated and a mitigation approach for correcting the situation is provided.

The calculation of proper sags and tensions of conductors and other wires are the most vital aspect of transmission line design; structure heights and placements are determined by the sags, structure designs are determined by the tensions, and lines are constructed using both of these methods. Mostly gone are the days of plastic sag templates. Or are they? Many use computer software programs thinking that they are using Technology for the Next Generation, yet they merely duplicate the archaic plastic template technology and thus their designs have sags and tensions that can have significant error. Additionally, their lines are built using these same assumptions and thus sags can be lower than anticipated or tensions can be higher than anticipated. This paper will discuss common errors made in the industry and suggest methods for more accurate sag and tension calculations for better structure and line designs as well as construction. It's time that we truly use Technology for the Next Generation and not continue to use these Electronic Sag Templates that merely duplicate what we've always done before.

Over the past number of years AEP and other utilities have been experiencing fatigue failures of steel davit arms in our Texas region, especially when used in conjunction with concrete poles. It was assumed that these failures were the result of conductor motion, either as a result of high wind gusts (wind sway) or smooth moderate winds (aeolian vibration). This paper describes the results of a field vibration study that was conducted on one line which experienced davit arm failures to establish the level of aeolian vibration versus wind velocity and vibration frequency. Also described are the results of extensive laboratory testing that were conducted on a vibration span to determine the relationship between conductor motion, the davit arm motion, and the fatigue stress on the arms. Further laboratory tests were also conducted to determine if dampers used to control aeolian vibration on the conductors would have a mitigating effect on the davit arm failures. Further long-term field measurements are planned on a line where davit arm failures have occurred to collect data on a full scale span and to verify the preliminary findings of the laboratory testing.

Design of latticed steel transmission towers is a challenging task which involves lengthy modeling and detailing of significant amount of steel members and connections. Testing of the towers designed validates consistency between modeling and detailing and ensures the towers are designed to withstand design loads without premature failures. This paper presents lessons learned from design and testing of latticed steel towers in a recent project of developing a family of nine (9) 500kV transmission towers. The paper provides a discussion about the process of selecting bidders for design, detailing and fabrication of latticed steel towers, and abrief discussion of determining materials used in the towers. The paper also discusses comparisons of different tower weights for various tower base widths and foundation reactions to achieve a cost effective design combining both the tower and its foundations. Examples of modeling tower members using beam elements in PLS-TOWER are presented to illustrate the importance of fully understanding the main purpose of using beam elements in TOWER. Variations between tower modeling and detailing are presented with specific attention to member and connection eccentricities. Finally, lessons learned from six (6) tower tests are discussed.

The electric transmission industry is booming. Several billion dollar scale mega projects are being routed and permitted, some are nearing start of construction and some are complete. Asset owners have struggled with engineering, material and contract labor resource availability and, as a result, have discovered several new methods of delivering these major projects. This paper will examine several major projects and discuss the lessons learned on each of the project delivery methods that were selected to deliver these billion dollar scale transmission projects. The common methods of delivering major projects (programs) are design/bid/build, design/build (EPC) and program management.

When TXU Electric Delivery (now known as Oncor Electric Delivery) filed a CCN application with the Public Utility Commission of Texas (PUCT) in 2006 it planned to construct a new 345 kV line approximately 6.5 miles long on single pole structures. During the PUCT's review of the application the City of Dallas intervened in the process and requested that a portion of the line be constructed using UG technology. The new line was necessary to provide additional capacity and reliability to the Dallas Central Business District. The circuit needed to be rated at 3400 Amperes. After much deliberation, the PUCT ruled that Oncor should construct a 0.7 mile segment of the line underground. Thus began the first 345 kV underground project on the Oncor system. There are a number of 345 kV underground projects in service throughout the United States but none with a dynamic rating capability near the 3400 Ampere range required for this project. Selecting the correct technology and materials and developing a design to properly implement them has presented engineering (and political) challenges that Oncor will not soon forget. The line is currently under design and will be constructed Spring through Fall of 2009.

High voltage electric power transmission lines span various regions and geology, and with these variations in venue and subsurface conditions, comes the need for efficient foundation designs to control construction costs. In most locations conventional deep foundations prove to be economical for design and construction, and thus an optimum foundation system. In some locations, however, site conditions make conventional foundations too expensive or impractical, and micropile foundations become the prime solution. Micropiles are often thought of as an emerging technology, even though they were conceived over 50 years ago and have been used in the United States for more than 30 years. The electric power transmission industry has recently discovered this "emerging technology" and is beginning to take advantage of it. As the need to transfer electricity from more remote locations continues to expand, the use of micropile foundations will become more common as a practical solution for the challenges encountered. This paper will introduce and illustrate the basic advantages and disadvantages of both conventional and micropile foundations in this industry and how they are being integrated to provide design solutions. A brief history of the introduction of micropiles into this industry will also be discussed.

With increasing need for design support on transmission lines, engineers need to be comfortable in evaluating limited geotechnical foundation design data spread out over long distances. This report will show that through merging engineering geology and geotechnical engineering evaluations, data can be grouped into sections comprised of different design parameters along the length of a transmission line. The goal of this merger is to create a better characterization of the foundation design data along an entire alignment. Some tools and methods used by others are presented for consideration. When done well an engineer can better understand the nature of the foundation conditions along the alignment and why/where the geotechnical design parameters should be used and changed as a result of how they are grouped around similarities in geologic conditions.

Although close attention is paid to the design of transmission poles, many times the design of the foundation is left up to a "rule of thumb" method. Reliable and established methods for analyzing laterally loaded piles have been incorporated into the current study to calculate the required depth of embedment for transmission poles, and the results are compared to the current methods. The results show that the current methods for determining embedment depths for direct-embedded transmission poles significantly underestimate or overestimate the required embedment depth depending on the soil conditions. Recommendations are made for alternate design methods for transmission pole foundations. A case study is presented where direct-embedded wood transmission poles fell over due to inadequate foundation design. The results of the case study are compared to the methods presented in this paper. It is concluded that the alternate design methods will generate more accurate results than the current methods.

During the course of their service-life steel pole and lattice tower foundations are subjected to significant environmental forces that can have a detrimental impact on their service life. Foundations are critical components of all transmission systems and therefore are crucial to the national power grid. Deterioration identified in these foundations during regular inspections and assessment should be categorized into specific levels of structural severity. Each should be addressed accordingly by a varied regimen of mitigation and repair options. Coatings and anode installation are most commonly used to help prevent deterioration. Repair options include but are not limited to: bolted steel repairs, welded steel repairs, reinforced concrete encasement of concrete foundations and direct member replacement. This paper will address assessment and repairs specific to steel tower and steel pole foundations inclusive of structural durability, corrosion issues and standard repair methods.

Current standards define accepted methods of substation bus design. These standards also require certain strength and deflection criteria. This paper will examine commonly proscribed rigid bus design methodologies and compare them with actual field experience in the design of a 500kV switching station. Special attention will be given to required deflection criteria, methods commonly used to achieve these criteria, and results actually measured in the field.

This paper reveals a new approach to the design of civil engineering components of a substation. A design pattern is presented that enables the engineer to design and generate 3D structures, foundations, oil containment devices and soil cut and fill of a substation. The process is automated for minimum user operations and the final product is a 3D model of the entire substation. For the client, the outcome is cost reduction, better quality control, overall lifecycle project time reduction and a virtual realistic representation of the substation that can be looked at from different angles and directions. Quantities for cost estimation by the project engineer are readily available from the 3D model. This paper also portrays the 3D model of a substation as a virtual tool that embraces all aspects of the lifecycle of a substation project.

The 2008 Edition of ASCE Manual 113, "Substation Structure Design Guide," devotes several sections to criteria and procedures for the seismic design of structures and components of electric substations. This paper describes concepts that interpret and supplement the seismic provisions of Manual 113. Among the issues discussed are: definition of seismic design spectra, simultaneous occurrence of ground motion in three mutually perpendicular directions, incorporation of soil-structure interaction effects and estimation of deflections under seismic loading. Numerical examples are presented to illustrate some concepts, and recommendations are given to implement them in practice.

Fault currents are increasing on existing and new substations due to system additions and modifications. Bus designs are typically based on the circuit breaker rating of 40kA to 80kA. Phase spacing is no greater than that required by insulation level, thus for configurations in the 115kV to 138kV range, magnetic forces over 100 pounds per foot are not uncommon when computed per IEEE 605 methods. The magnetic force calculation in IEEE 605 is proportional to the decrement factor squared and 1.6 is the default decrement factor. The first reduction strategy is to calculate the actual decrement factor. The decrement factor is a function of fault clearing time, system reactance and system resistance. Typical system reactance to resistance ratios (X/R) can reduce magnetic force 12 to 18 per cent for a two cycle breaker. More reduction is available with greater clearing times. The second force reduction strategy is to compare the natural frequency of the bus to the forcing function frequency. This paper presents a simplified generalized coordinate method to determine the frequency based response of the bus to the magnetic field. The paper will also review the cost savings as a result of applying these techniques.

This paper discusses some of the recent wind loading procedures for the design of transmission lines (NESC, ASCE, IEC, CENELEC, etc.). It provides some detailed background behind their formulas for gust factors, span factors and gust response factors. It discusses the uncertainties inherent in each one of the parameters and assumptions behind the formulas: wind storm type, reference wind, terrain roughness, profiles, gustiness, time and spatial correlations, dynamic response, wind direction, drag coefficients, etc. It provides some examples to illustrate the current lack of consensus and to identify the important design parameters. The paper concludes that the complexity of most current wind design procedures is not justified. Instead, it provides the rationale for simplifying the entire wind design process and it offers specific recommendations for achieving that goal.

Current criteria for the calculation of synoptic wind load effects on transmission line components are based on Davenport's gust response factors, which take into account the different response of structures and long spans of wires to turbulent wind. The gust factors include resonant components that imply possible dynamic amplifications of the wind effect on the structures and wires, although the wire resonant response is generally ignored because of high aerodynamic damping. Although the gust response factor equations were derived for 1-hour mean wind records, the factors are being applied for winds with different sampling intervals but with reference to 10-minute winds. The conversion is based on Durst's velocity ratio curve, which was not derived from records of extreme winds but from low velocity storms. Due to these differences, and also other simplifications, there could be errors in calculated line or component reliability of at least one order of magnitude. While line design weather loading conditions are derived from synoptic wind records, it is well known within the industry that most line or structure failures are induced by non-synoptic storms, such as downdrafts or tornadoes generated by thunderstorms. Field evidence from these storms indicate that the 1-hour mean factors, even when extrapolated to very short-interval gusts, do not explain the observed effects and therefore new span and gust factors are needed for design. The paper reviews the basic concepts and history of span and gust factors and the impact of some of the current assumptions and simplifications. It also focuses on recent research on the actual effects of non-synoptic storms and the new factors that are derived from these experiences.

This paper discusses ASCE 74, IEC 60826, and NESC (Rule 250C) extreme wind load methodologies applied to transmission line towers and conductors. The application of these methods can result in varying loads applied to towers and conductors. The wind parameters used and some of the differences between these wind loads methods will be discussed. This information will help utilities to better understand the limitations and assumptions used to determine design wind loads on transmission line conductors and towers. Comparison of wind load results performed by the CEATI International, Inc., using the ASCE 74, IEC 60826, and the NESC methods are presented. Also presented are issues that should be investigated to develop or enhance future wind load methods.

Ice shedding and the subsequent conductor jump have been of interest to transmission and distribution designers since the early 1900's. Some of the factors that affect the height of the jump and the transverse movement of the conductor are ice thickness, ice density, phase to phase and span to span patterns of ice loading, the pattern of ice shedding within the span, the wind speed, conductor size and stranding, line angle, structure type, span, and elevation differences between supports. This paper reports the results of finite element dynamic modeling of ice shedding from a 500 kV single circuit tubular steel transmission line. Ten spans of line were modeled including all three phases and two shield wires. The structures and insulators and shield wire hardware were also modeled. All simulations were performed using the commercial finite element program ADINA.

The electrical utility industry has been using weathering (Cor-Ten^TM) steel products for nearly 40 years. Along with the cost advantages to utility owners, it also provides more flexibility for pole manufacturers. Thus, the whole industry, from structural designers to construction workers, can benefit greatly if its unique characteristics are fully recognized and utilized. However, weathering steel cannot be used in a carefree manner. Like all other materials, regular inspections and maintenance work needs to be performed in order to prolong its service life. What activities are required in order to achieve an efficient and effective assessment? Are most inspection programs adequate enough to find potential problems? What exactly are these `potential problems'? What long-term maintenance activities are required? Performance-wise, are weathering steel poles really a time-bomb waiting to be ignited as some have claimed? Or is the bad reputation of weathering steel simply the result of misunderstanding and misuse? Also, what about the use of weathering steel in other industries? It was fashionable to use weathering steel in the building and bridge industries during the 1970s. Do those industries face the same concerns? Do they now face the same exposure? Is there anything we can learn from them? This article attempts to provide basic background on these questions and hopes to stimulate further study and discussion in this area from the utility industry.

Transmission Line Catenary structures are steel cable structures from which transmission circuit conductors are suspended. The objective is to keep the entire support structure above locations of high avalanche risk where other structure types have little chance of surviving. The world's first Catenary was built in 1955 in British Columbia, Canada. The authors have engineered and provided construction management for the installation of the world's second and slightly larger Catenary. It was installed 1,000 meters north of the first. The authors have also installed a smaller Catenary and done preliminary engineering for thirty four other Catenaries, all in British Columbia. This paper discusses transmission line Catenaries in general and will describe the 2007–2008 engineering and installation of Catenary 2 in detail.

Transmission line construction during the early 1900s was primarily dictated by engineering issues with little devotion to mitigating visual impacts on the surrounding environment. Beginning in the 1960s and 70s, a new environmental ethic began to make its way into the planning process. As a result, heightened sensitivities to visual impact issues are now the norm on new transmission projects, thus making them a major objective on newer projects. This paper addresses the aesthetic challenges confronting future expansion of transmission lines, such as overcoming public objections, environmental stewardship and improving the appearance of transmission facilities. The paper uses illustrations, photographs and case studies to review current solutions by American Electric Power ("AEP") and other utility companies to reduce visual impacts on transmission projects. Current best practices revolve around route development, structure design, topographically sensitive siting techniques, off-site mitigation, accurate visual simulations, stakeholder input, construction management, and special structure and conductor finishes. Finally, the future of transmission line siting is discussed along with areas of needed research. These issues challenge the engineering team with the opportunity to provide innovative, creative solutions.

Alabama Power has successfully installed the new 3M Aluminum Conductor Composite Reinforced (ACCR) high temperature, low sag conductor on a 2.5 km (1.5 miles) section of a 230 kV transmission line, utilizing the existing lattice steel structures located in a congested corridor with 230 kV and 500 kV line crossings. The upgrade was necessary to provide additional capacity to meet future (short term) load demand and line loading under contingency conditions. This paper provides a case study of the evaluation, selection and installation of the 3M conductor and highlights the challenges during the design and construction stages of the project.

This paper describes the foundation challenges involved in building a new 12-mile 230kV double circuit line. The project consists of 228 pole structures on base plated steel caissons. Portions of this line are located in a coastal salt marsh, adjacent to a state wildlife sanctuary. Other portions wind their way along an environmental superfund site, and through multiple refinery, petrochemical, and heavy industrial facilities that have been under continuous use since the early 1900's. Current environmental and wildlife restrictions as well as requirements for hurricane loadings ruled out many conventional forms of design and construction, as did restrictions imposed by industrial facilities along the route that severely limited access. Because of this, a decision was made to use helicopter construction over much of the project. Structures and caissons were designed and constructed in sections to allow the use of a helicopter to lift to its maximum capacity. The helicopter then transported and installed each section at its intended location. In some instances where the steel caisson foundations were too heavy for the helicopter to lift, they were manufactured in two pieces and field welded. The various foundations features involved in meeting an aggressive in-service date under difficult conditions are described in the paper.

Wood County Electric Cooperative is serving a new pumping station for the Dallas Water Utilities on Lake Fork in eastern Texas. The optimum route required a lake crossing of over 1,738m (5,700 ft) for a double circuit 138 kV line. Lake Fork is an internationally recognized bass fishing environment, holding the Texas record for the largest bass, weighing over 8kg (18 lbs). The placement of the foundations for the crossing structures presented several unique challenges including limiting the number of structures set in the lake, providing clear channels for boating traffic, minimizing environmental impacts and working in lake depths over 15m (50 ft). This paper discusses the types of foundations considered and the design and installation of the most effective design.

Seattle City Light (SCL) owns and operates 3 dams in the North Cascades of Washington State which provide about 30% of the utility's needs. Four 230kv circuits carry electricity from these dams to the Seattle area on two parallel alignments of double circuit lattice towers. The alignments cross the Skagit River near the town of Marblemount. At this crossing a major flood event in October of 2003 eroded 50 feet of high river bank in the direction of two lattice towers leaving about 75 feet from the tower bases to the edge of the river bank. In the 1930's the distance from the river bank to the towers was about 200 feet and in the 1950's was about 150 feet. Because of the possibility of further erosion by subsequent flood events Seattle City Light began a study to determine how best to mitigate the risk. The final design choice was to locate two 175 ft. steel monopoles on drilled pier foundations further from the river. The foundations would remain in place as essentially "bridge piers" in the event that future floods might erode the bank and leave the structures in the river. The future design condition would expose the top 40 feet of a 90 foot pier above the bottom of river scour. Several unique design conditions had to be addressed including a 100 year flood event (103,000 cu. ft/sec) and a seismic design event. The design also had to address how these loading conditions would be combined with the National Electric Safety Code (NESC) weather conditions. In addition the Corp of Engineer river crossing clearance requirements had to be maintained and there were other construction contract elements that had to be met such as sensitive area requirements, impacts to fish, and access.

Over the past 7 years Burns & McDonnell has been given the opportunity to provide program management and detailed design for Northeast Utilities (NU) subsidiary Connecticut Light and Power (CL&P) on their Middletown Norwalk 345-kV Transmission Project. The project includes 69 right-of-way miles of 345-kV and 115-kV overhead and underground transmission line. This $1.2 Billion project was completed in December, 2009. In order to provide support to the project locally, Burns & McDonnell established an office near the project site that has been staffed with over 70 professionals. Under the final design approximately 45 right-of-way miles of this line were constructed as overhead transmission lines with over 120 actual miles of overhead line. This will require just over 770 new, single, and multiple pole structures to be installed. To accommodate these structures just under 900 foundations will be required. Given the large scale and conditions of this project, there have been many challenges to overcome regarding these foundations. Initially one of the largest challenges was determining the type of foundation to use given the rocky terrain. Creating a design process for the different possibilities was necessary. Geotechnical and environmental questions as well as issues encountered during the actual construction have also provided significant challenges. Additionally, the unusually long project timetable created challenges and required a massive coordination effort. This paper will discuss these different challenges and how they were overcome.

Construction projects throughout the world have become more complicated and logistically challenging as environmental stipulations become more demanding and the effects climate change become more pronounced. No where is this more evident than in the sub-arctic, in this case interior Alaska, where Golden Valley Electric Association, Inc. (GVEA) is the Owner of the recently constructed 230 kV Northern Intertie transmission line project. This transmission line project is underlain by "warm" discontinuous permafrost prevalent throughout interior Alaska. The potential for change in the marginal permafrost over the life of this project had to be addressed at the design phase to provide the most economical project. This case study discusses the challenge engineers and contractors alike faced in scheduling, accessing and constructing a project across four distinct geographic areas, with an emphasis on permafrost zones. Contractors faced extreme weather conditions where summer sun shown for as much as 21 hours, to winter conditions with as little as 3 hours of daylight. Temperatures during construction varied between 32°C (90° F) and –45° C (–50° F). Without a clear understanding of design parameters between the Engineer and Contractor, projects can easily become problematic.

Cedar Rapids, IA experienced an unprecedented flood of the Cedar River in June, 2008. The previous record flood was exceeded by over 11 feet, surpassing the 500- year flood zone in much of the city. Over 9.5 square miles of the city was directly affected. Two major generating plants, the central business district underground electric vaults, and over twenty substations were damaged and/or destroyed. Recovery and rebuilding the system required innovative solutions to emergency restoration of electrical power. This paper will describe the severity of the damage and detail the innovative solutions used to rebuild a key substation required to restore electric service to the city's downtown distribution network.

This project resulted in an unusual challenge to augment two existing 46kV underwater circuits with an overhead double circuit line designed for future 115kV operations. The probable reasons to go underwater for the original 46kV circuit lines and the reasons for the new 115kV circuit lines to go overhead are discussed in detail under "Project Background and Requirements". The new line had to cross approximately 3,600 ft. of the Gulf Intracoastal Waterway at St. Andrew Bay. In addition to constructing facilities in an active waterway, the design of the overhead line had to consider and accommodate water depths of 60 ft. and provide sufficient span and clearance to allow for barge traffic. The 115kV overhead crossing of the St. Andrew Bay required the installation of four structures within the waterway consisting of tubular steel poles supported by concrete caisson foundations. Foundation and structure installation was performed off of two barges. The concrete caisson foundations were constructed by installing 6 ft. diameter pipe piles with a vibratory hammer and then filling the pipe piles with reinforced concrete. Environmental issues and shoreline stabilization were a part of the consideration for this project. This paper describes the various design and construction challenges encountered in this project.

This Paper describes the challenges faced during the construction of EHV transmission lines which travel hundred of miles in difficult terrain, under varying and extreme environmental conditions using variety of construction equipment. The engineering challenges become much more difficult with higher voltages as structures become very tall and heavy. Every country has individual challenges which are unique to that country or region. Engineering solutions need to be suitable to overcome working challenges which are described throughout the paper.

Encroaching vegetation poses a continuing threat to transmission line reliability. Vegetation-caused outages can result in heavy fines levied on the service provider. A rapid, accurate and cost efficient system for identifying encroaching and proximate vegetation with the potential to threaten transmission line reliability is described in this paper. The system is based on airborne Light Detection And Ranging (LiDAR) data, downward looking imagery and Global Positioning System (GPS) technology. Following the data collection stage, the geospatial information is processed and then modeled in Power Line Systems® Computer Aided Design and Drafting package (PLS-CADD^TM). Output data from this software is subject to filtering algorithms and used to create detailed plan sheets, providing a record of encroaching vegetation. This information can form the foundation of an actionable and auditable Transmission Vegetation Management Program (TVMP), as set out by NERC reliability standard FAC-003-01. The system detects and accurately locates trees and other objects that could cause flashovers under multiple line operating conditions, as well as trees that could infringe upon statutory clearance requirements were they to fall into the transmission line right of way (ROW). Predictive growth factors can also be incorporated into the models. The use of LiDAR as an effective vegetation management support tool is then evaluated with a case study in the UK.

Like many utilities, American Electric Power (AEP) has concerns regarding the longevity of new high temperature low sag conductors using non-traditional materials. For example, conductor designs such as ACCC (Aluminum Conductor Composite Core) and ACCR (Aluminum Conductor Composite Reinforced) that have entered the market in recent years as well as other new conductor designs that may be coming in the future. While vendors of the new conductors generally run their product through individual tests such as sheave, galloping, aeolian vibration, etc., they typically do not run a single sample through a sequence of tests to represent the mechanical loadings that generally occur during installation and operation of an actual line. For example, conductor installation (sheave testing), exposure to galloping conditions, aeolian vibrations and tension cycles due to varying weather loads. AEP has developed a testing protocol with the goal of evaluating new conductor designs in a few months (approx. 90 days) rather than having to wait years. In order to verify that the testing protocol is not excessively burdensome, AEP has partnered with Alcan Cable and Kinectrics to run samples of commonly used Drake ACSR (Aluminum Conductor Steel Reinforced) and Drake ACSS (Aluminum Conductor Steel Supported) through the same protocol. The only difference between ACSR and ACSS is that ACSR is stranded using hard-drawn aluminum wires, while in ACSS the aluminum wires have been annealed to remove any hardness and strength due to the wire drawing process. This paper discusses the findings of the test program. See Table 1 for the conductor properties.

Hydrogen sulfide (H₂S) is a colorless, toxic, and flammable gas with a characteristic odor of rotten eggs. It occurs naturally in crude petroleum, natural gas, volcanic gases, and hot springs. It can also result from bacterial breakdown of sulfates in organic matter, such as in swamps and sewers. H₂S gas forms sulfuric acid when concentrations exceed approximately 2.0 ppm and causes corrosion on many underground construction materials and is particularly devastating to concrete and steel. Temperature can accelerate chemical corrosion due to creation of sulfuric acid. Warmer climates -southern US cities, for example - have more corrosion problems. It can also lead to sulfide stress cracking. This paper addresses the corrosion issues due to H₂S gas on some galvanized steel transmission poles and the precautions taken related to the removal and replacement of the direct embedded steel poles with base plated steel poles on a traditional concrete pier foundation. This was a dangerous situation, but also an interesting exercise in developing a solution to the abatement of the toxic and corrosive gas, as well as evaluation and removal of the pole itself. Special techniques that were necessary in dealing with the toxic gas that may prove beneficial to others who may come across similar situations.

Line rating and uprating techniques have become very popular methods for evaluating and increasing the capacity of existing transmission lines. Highly accurate aerial LiDar surveys have enabled transmission engineers to precisely model wire attachment points and corresponding conductor sag. The utility industry has then used several methods of calculating, predicting and or measuring the conductor temperature and then calibrated it to the highly accurate survey data. The models of each transmission line are then used to evaluate the respective electrical capacity of each line and the results are used as a tool in determining the extent of uprating required. The line rating studies have resulted in many transmission uprating projects where significant capitol has been invested to increase the electrical capacity in each line. The line rating and uprating processes have leveraged technology to maximize capital investments; however, how accurate are the results? Are the results conservative? Are they too conservative? What is the margin of error? Is there a disconnect between the Operation's system models and Engineering's models used for Line Rating Analysis? Planning and Operations department typically use the Institute of Electrical and Electronic Engineers' (IEEE) Standard 738 calculation methods to predict operating temperatures on transmission lines per some set of operating criteria for a given season. This standard states in the introduction that "because there is great diversity of weather conditions and operating circumstances for which conductor temperatures and/or thermal ratings must be calculated, the standard does not undertake to list actual temperature-current relationships for specific conductors or weather conditions." Is this standard applicable or helpful to Line Rating analysis? This paper will explore many of the methods used in line rating analysis, focusing on the methods of determining the calibrating conductor temperature. A comparison of each method will include a brief methodology and an error analysis of maximum possible error and probably error, positive and negative.

Transmission line (TL) structures are generally designed with a simplified static-equivalent approach described in the industry documents (IEC 60826, CENELEC, ASCE 74). These static equivalent methods are based on extensive in-situ testing and have been shown to be appropriate for typical TL structures. However, wind loading is a dynamic loading, and for certain cases it is difficult to capture dynamic response of the structure by a static equivalent method. As well, static equivalent method has limitations and the industry documents do not give any directions to design structures out of their scope. In this article, a set of numerical tools were used in order to assess wind-structure interaction for TL structures. At the present, the dynamic/turbulent wind loading data were numerically generated. The TL structures were modelled using finite element (FE) method that takes into account the inherent nonlinearities. Two wind loading studies are presented here: (i) a guyed tower; and (ii) a river crossing. The guyed tower was studied to show that its dynamic behaviour can have significant impact on wind effect on the structure which cannot be captured by static equivalent method provided in the industry documents. The river crossing was studied to understand better the implications of applying wind loads extrapolated from the ones used for normal TL structures, as compared to dynamic wind loading. For each case, comparisons with results obtained with static equivalent method are presented and discussed.

Lattice steel transmission towers have been used to support transmission lines over the past 120 years. Many events have been known to damage these towers to an extent to which they must be repaired structurally. These events include but are not limited to vehicle impacts, agricultural equipment damage, corrosion damage, vandalism, and initial fabrication / construction errors. It has been the standard practice of transmission utilities in the past to produce the steel detail drawings in house, and either have their own line maintenance crews make the steel changeout or to have an electrical contractor perform the work. Most often, the responsible engineer at the utility will specify a load that must be supported during the work. There is an old wives tale prevalent among electrical contractors that the towers are "designed" to stand on three legs. This no doubt comes from the fact that many of the foreman and supervisors in the industry have personally seen the towers stand with one leg removed. In fact, many tangent and light angle towers will stand with one leg disconnected with no temporary support. However, with the many combinations of tangent, light angle, heavy angle, and dead end configurations, wire tensions, and construction / design practices, it is imperative to communicate that a general "blanket" statement that the towers will stand on three legs not true. In fact, allowing this blanket statement to be used in the industry is incorrect. It is the purpose of this paper to discuss the correct procedure(s) for temporary support of towers and outline the correct safety factors that are given by OSHA, ASME, and the governing utility. The focus will be on cranes supporting towers and the applicable safety factors. Additionally, alternative temporary support options shall be discussed.

Paper describes the major storm event which happened when a cyclone `GONU' lashed OMAN on 5^th June 2007. OMAN electricity and Transmission Company asked for quickest restoration solution. Damaged sites were not reachable due to floods. Various solutions were considered and finally quickest solution was adopted to erect 50 wooden poles. Restoration of one circuit of 132 kV Transmission line was done in 8 days after mobilizing men and material. Power was restored on 20^th June 2007. Paper describes entire event, engineering solutions along with actual site photographs.

Existing structures were aluminum double-circuit lattice towers with a single circuit installed and had to be evaluated for the proposed addition of a second circuit. Original design data drawings were not available for these towers. Therefore, field measurements of towers with an energized single circuit were performed to determine overall tower geometry, individual member sizes and connection configuration. Field hardness testing and sample coupons were taken for laboratory analysis to determine material properties. Loadings for the towers were determined in accordance with the 2007 edition of the National Electrical Safety Code. Analysis and qualification of the towers were performed using the software program "Tower" by Power Line Systems (PLS Tower), and the "Guide for the Design of Aluminum Transmission Towers" as published in the December 1972 Journal of the Structural Division, Proceedings of the American Society of Civil Engineers. The existing foundations were checked against the support reactions from the PLS Tower Analysis. This paper describes the various analysis challenges encountered in this project.

Starting in 1969, American Electric Power (AEP) built a 765kV transmission network that amounted to over 2,000 circuit miles by 1984. The system utilized four—conductor bundles of Rail and Dipper conductors. Operational experience with the network revealed issues around audible noise due to corona from the lines. In 1990, when the need arose to expand the network, it was decided that audible noise issues would be addressed by utilizing a new bundle design that consisted of a 6-conductor bundle using Tern conductors. The intent of the design change was to eliminate corona and thus resolve the audible noise issues associated with previous designs. The new design would also allow the use of non-ceramic insulators, which are susceptible to damage from long term exposure to corona. The move to the 6 x Tern phase bundle posed significant mechanical and electrical challenges to the engineers involved in hardware development. This paper describes the extensive electrical testing programs carried out to prove the performance of the new 6-conductor bundle design.

This research presents the results of a test program to determine the compression strength of single angle members subjected to short duration axial load. Lattice steel transmission towers are largely constructed of single angle members. When a conductor breaks, the load on the tower is of large magnitude but short duration. This research attempts to answer two questions: 1) do angles in transmission towers have a higher compressive strength under short duration axial loads than they have for static loads; and 2) if they have a higher short duration axial capacity, how can this be used by transmission tower engineers. The parameters of the short duration axial load to simulate a broken conductor applied to the angles, as a function of the time, were determined using CIGRE B2-308 (2004). This reference discusses a full-scale test of a broken conductor and insulator on a transmission line. Time history plots of transmission line component loads are presented and used to develop the short duration load function for this study.

Over time, steel structures are affected by corrosion and their capacity is therefore affected. To estimate the capacity of structures with corrosion, it is necessary to estimate the residual capacity of corroded members. The objective of this article is to evaluate the structural behaviour of corroded steel angle members under compressive load in order to provide practical data to engineers. An accelerated corrosion procedure was used on 16 angle members. The angle members were then tested in compression. The influence of corrosion on compressive capacity was measured and compared to analytical methods accounting for weight loss. Recommendations are drawn from this research to provide guidance to engineers on how to evaluate compressive capacity of corroded members. Needs for future work are also highlighted.

This paper covers the importance of achieving good adhesion strength when applying Below Grade Coatings to steel structures. In particular, galvanized structures. Through research, development and testing in accordance with ASTM D4541 we have concluded that there is a very meaningful correlation between a high pull-off adhesion value and the durability of an applied coating on a steel structure. The higher the pull-off adhesion strength, the better the bond to the substrate material. Having a superior bond will better enable the coating to withstand harsh weather and physical conditions. It is imperative that when using a blast technology to prepare a surface for a Below Grade Coating that a high level of attention be placed on not only the profile of the galvanized steel surface after blasting but also the surface roughness achieved. Having an insufficient surface roughness can lead to an undesirable adhesion strength of the Below Grade Coating and may compromise the intended performance for which it was engineered/developed. The importance of establishing a reliable and consistent surface preparation method is critical for providing a foundation that will enable a superior pull-off adhesion value, which will provide a more robust coating solution.

With the ever increasing demand on high voltage transmission systems minimizing outages has become an even higher priority. For transmission lines located in regions of the country that experience conductor galloping, this phenomenon can significantly contribute to the flashover rate if not properly accounted for in the design of the line. Recent experience in some areas has shown that traditional methods of calculating the magnitude of galloping ellipses do not provide adequate phase separation. An alternative method being evaluated is the design approach proposed by CIGRE. The CIGRE methodology is derived from actual galloping observations and incorporates conservative empirical approximations. While this conservatism minimizes the probability of flashover or conductor impact during galloping, it also leads to larger vertical and horizontal phase spacing which directly affects structure configuration and cost. The impact can be even more significant for rebuild or reconductor projects where the original design criteria did not consider the larger CIGRE galloping ellipses. This paper provides a comparison of galloping ellipses calculated by CIGRE with traditional methods and includes several examples of the impact on structure configuration, structure weight, and foundation size.