Aging Power Delivery Infrastructures

H. Lee Willis, Randall R. Schrieber

• Publisher: CRC Press
• Year: 2017
• ISBN:
  9781351832540
• Edition: 2
• Topic: Biological Sciences
• Subtopic: Science General
• Index: Biological Sciences

Good aging infrastructure management consists of optimizing the choice of equipment and its refurbishment while also making compatible changes in all those operating and ownership policies, the whole combination aimed at optimizing the business results the power system owner desires. Both a reference and tutorial guide, this second edition of Aging Power Delivery Infrastructures provides updated coverage of aging power delivery systems, the problems they cause, and the technical and managerial approaches that power systems owners can take to manage them.

See What's New in the Second Edition:

• 
  
  

• All chapters have been updated or are completely new
• Comprehensive discussions of all issues related to equipment aging
• Business impact analysis and models and engineering business studies of actual utility cases
• Strategy and policy issues and how to frame and customize them for specific situations

This book looks at the basics of equipment aging and its system and business impacts on utilities. It covers various maintenance, service and retrofit methods available to mitigate age-related deterioration of equipment. It also presents numerous configuration and automation upgrades at the system level that can deal with higher portions of aging equipment in the system and still provide good service at a reasonable cost.

1 Aging Power Delivery Infrastructures

1.1 INTRODUCTION AND OVERVIEW

This chapter provides an overview of aging power delivery infrastructures, their characteristics, the issues they create, the challenges they present, and the methods and processes utilities and the power industry will use to meet those challenges. It is divided into nine sections that cover different aspects of aging power infrastructures, all from a high-level, big picture perspective. The rest of this book fills in the details. This Introduction and Chapter 17 - Guidelines and Recommendations, taken together constitute an executive summary.

Gradually Growing Older

America’s electric utility systems are growing older. In many systems, significant portions of the equipment and facilities in service date from the economic boom following WWII, or from the sustained growth period of the 1950s and 1960s that many American cities and towns experienced. A lot of equipment installed then, and still in service today, is between 50 and almost 70 years old.

As electrical equipment gets older, it deteriorates from the wear and tear of service. At some point, it wears out. Then, it may fail outright, or more often, succumb to forces it would have withstood when new but no longer can - the high winds of a storm or the rare electrical spike caused by switching or lightning. Such failures cause interruptions in service to the utility’s customers, and require expensive emergency repairs and system restoration work. Monies will have to be found to pay for that work and the cost of replacement equipment.

All equipment eventually reaches an age where deterioration and increase in failure rate is significant. This is the first fundamental truth of aging power infrastructures. Electric utility equipment is designed and built to be incredibly robust, but eventually time wins: sooner, but usually later, everything fails. A second fundamental truth for most utilities is that it is no longer sooner and that it will soon be later: large portions of old equipment are approaching an age when they are not going to provide dependable service without considerable attention.

A portion of the equipment installed fifty to sixty years ago has already failed in the decades since. Storms, floods and other natural disasters took their toll. Accidents, such as a power pole being hit by a car or an underground cable being dug up by a construction crew, happened. Sometimes equipment just failed for no obvious reason. Regardless, all that equipment was replaced when it failed. As a result, even in the oldest areas of a system, there is a mix of old and new.

But the old predominates. Even in areas built immediately after WWII, rarely has more than 25% of the equipment been replaced in the intervening decades. Well over 70%, and often more than 85%, of the equipment is original in spite of being more than five decades old. That creates a practical operating problem for a utility. Some of the equipment is new. The biggest portion, although having spent decades in service, is still good enough to provide satisfactory service for a decade or more to come. But a tiny fraction of the old is badly deteriorated, perhaps not to the extent that it shows visible signs of imminent failure, but to the extent that it cannot do its original job dependably. Those failures will poison the performance of the system overall.

It might seem that this problem is easy to solve. Just have the utility find and replace all the equipment that is going to fail in the next few years, and do that on a continuing basis. Realistically, that is not easy to do. First, the level of failure considered “bad” is remarkably low. Power systems depend on long chains of transmission lines, substations, transformers, breakers, feeder circuits, reclosers, sectionalizers, fuses, cutouts, service transformers and service drops. All must function well if the utility is to deliver reliable power to its customers. If anything fails in this chain, some utility customers go without power until service can be restored.

Thus, an equipment failure rate of only half a percent per year would be disastrous. It would mean service interruption rates that are completely unacceptable to customers, regulators, and stockholders alike, and emergency field work rates that exceed the utility’s ability to dispatch crews to do the work. Under normal circumstances, less than two tenths of one percent of equipment in good condition fails in a year. Thus, finding the future “bad actors” in a power system is a challenge – the proverbial needle in the haystack. A utility might have 8,000 steel lattice transmission towers in service, and it will be a very bad year indeed if more than four give serious problems.

Finding that flawed equipment is not easy. In many cases, badly deteriorated equipment does not give obvious signs of its undependability. Tests can be done to improve the knowledge the utility has of equipment condition. But those require skilled personnel, always in short supply, and expensive specialized equipment. And many tests are intrusive to customers: utility technicians have to go into backyards and factory property to set up and run their tests. In downtown areas they must cordon off lanes of major streets while they work in equipment vaults under the pavement.

Furthermore, test results are not entirely dependable. A test that is 95% accurate may sound as if it is a good test – and it may be the best available – but its unrestricted use creates problems. Suppose a utility has 10,000 older wood distribution poles, of which 500 (1/2 percent) are truly so deteriorated as to probably fail in the next decade. A 95% accurate test will find 475 of those, leaving 25 bad poles in the field. That alone is a concern, but not the major worry from this test. The real concern is that if it has a 5% false positive rate, too, then it will identify 475 of the 9,500 good poles as bad, for a total of 950 poles it indicates should be replaced. If the utility follows those test results it will replace twice as many poles as necessary – and incur twice the cost. The test may be the best that can be done in the circumstances, but it is not the type of clean, effective solution that inspires confidence among all stakeholders.

Furthermore, replacement of equipment already in place is very costly. Of course, there was a significant cost associated with the original installation – what is often called “greenfield” site work. Money was required to buy a pole or transformer or cable, and skilled labor was needed in every aspect from design to construction. But the cost of replacing that equipment many years later is much greater. First, before the new equipment can be installed the old equipment has to be removed and recycled, etc. Then new equipment has to be put back into place and reconnected to the rest of the system. Further, typically this work must be done while the rest of the system is in operation – i.e., energized – so that service to customers is not interrupted. That means the utility’s personnel must work in and around live electric equipment. Such work can be done safely, but will proceed much slower and cost more than the de-energized site labor that was used in the original installation. As a rough rule of thumb, replacement work is two to three times as expensive as an initial greenfield installation.

Thus, replacement of even a small portion of an aged system can be a formidable financial burden to a utility. Going back to the 10,000 wood poles discussed above, the utility would follow up its test results by replacing nearly 1000 poles in order to obtain a failure rate over the next decade only slightly above that for all-new equipment. That may sound like a good bargain. But those replacements will each cost about three times as much as new poles cost when originally installed, and again, it is replacing more than two poles for every failure it will avoid, even though the test procedure is 95% accurate. And those tests, themselves, have a noticeable cost, as does the effort to correlate test results and manage the pro-active replacement in and around all the other activity the utility has keeping the lights on 8,760 hours a year. Altogether, the utility will spend roughly 5% of the cost of the original construction of the entire line for these 10,000 poles (adjusted for inflation, etc.) in order to keep failures and their consequences under control for another decade: or about half a percent per year.

To put that half a percent capital expenditure in perspective, consider that a typical utility might add about 1% new equipment each year for system expansion – as its customer base and energy sales grow. Traditionally, the rates that it charges its customers, the budgets it puts together and manages to each year, the number and types of field crews and materials and equipment supply infrastructure it has, and its management bandwidth, too, are all geared to that level of capital spending and construction. This additional half a percent cost to pro-actively handle aging equipment is a 50% increase above that traditional rate of capital spending on system equipment “additions.” To a company that may have only a single-digit profit margin, that finds it difficult to hire skilled field personnel and managers, this can appear to be an untenable challenge.

Against this, however, is the undeniable fact that O&M costs for repairs, restorations, and replacement for failures are and will continue to rise in the foreseeable future as the system continues to age, and that if the utility manages pro-active programs well, they will ultimately reduce cost as compared to that. The utility has no choice but to adapt with new testing, tracking, evaluation, analysis, planning, and management approaches to control its infrastructure aging.

In any practical sense this issue of aging infrastructures is new to the utility industry. During the last half of the 20^th century, electric utilities in North America, Europe and in many other places around the globe developed and institutionalized incredibly efficient methods and processes to run a utility system while providing high levels of reliability (§ 99.98%), all at costs that regulators accepted as being as low as practically possible. Then, equipment that today is 60 years old and beginning to give problems was only 20 to 40 years old and still quite robust.

Since the problem of aging infrastructures was not a priority then, utilities and the power industry did not set themselves up to address it. Nor was it a focus for equipment manufacturers and service providers that support utilities: they go where the market leads them. Even only twenty years ago – half a career ago for senior managers and the most experienced engineers and operators at a utility – this problem did not exist in any measure serious enough to make it a priority. The challenge the industry now faces is to change this situation in time to effectively control aging and its impacts before the problems they cause become serious.

1.2 AGING INFRASTRUCTURE MANAGEMENT MUST BECOME A MAINSTREAM PART OF UTILITY OPERATIONS

In most cases it makes no sense to replace a system that was originally installed seventy years ago in a wholesale fashion. Even among the oldest equipment a majority may still be in serviceable condition and capable of providing many more years of good service. A utility’s best course is to do what it can to find the bad actors and the questionable equipment and replace only that, continuing into the future each year with a system that is old but in which its condition is being managed to a level optimized to balance service reliability and cost. The system will be old, but condition will be “good enough.”

Among other things, this means aging infrastructures are here to stay. Any utility’s system will age, until it at some point it has become “old,” a term the authors will define here as meaning the system has a sufficient portion of equipment deteriorated badly enough to cause the utility concerns about failures, breakdowns, reliability, and cost. Once a utility starts managing the condition of that aging infrastructure well, it will replace or refurbish deteriorated equipment that is in unsatisfactory condition, but retain all the old equipment that is still in satisfactory condition. The system will continue to include a lot of old equipment, and that older equipment will always have the potential to go bad in the future. Further, that equipment kept in service will continue to age. The aging infrastructure condition management program will not necessarily reverse aging, just control condition to some (hopefully optimum economic) point. The system will not be new, but neither will it be badly deteriorated.

To do that the utility will need some combination of on-going testing, tracking, mitigation of continued deterioration, and pro-active replacement and refurbishment of deteriorated equipment, will be needed on a continuing basis into the future. Such programs will control equipment condition to an “optimum” level, a stable, sustainable point at which equipment in service continues to age, deteriorated equipment is replaced, and the utility continues to test, maintain, and service and replace equipment sparingly but in a targeted manner, with overall cost kept at a minimum.

Utilities that today have no processes and budgets in place to do this type of condition management will have develop those capabilities. Those new processes will be folded into the traditional planning and construction and O&M management processes and functions that the utility has had for decades. And condition management will be mainstream utility practice: It is likely that by 2035, a significant portion of electric utilities in North America, perhaps as many as 40%, will be spending slightly more capital each year on replacing aged and deteriorated equipment than on system expansion due to load growth.

1.3 WHAT IS THE INFRASTRUCTURE INVOLVED?

Even a power system serving only a few thousand customers is made up of tens of thousands of individual components – poles, ducts, underground vaults, substations, transformers, circuit breakers, voltage regulators, monitoring and control systems, service transformers, meters, transmission towers, and electrical conductors (wires). To many people this all-inclusive set of equipment is the infrastructure. But the comprehensive view that leads to the best solution to aging and the problems it causes says there is more. The methods of operation of the system are a big part of how the power system performs. For example, three cornerstones of utility operation are:

1) Loading specifications – the guidelines the utility sets on the amount of electrical or mechanical load permitted on a unit – influence how much wear and tear it experiences, how much burden it is expected to carry, and how much its failure affects service reliability.

2) System operating guidelines – the procedures and priorities for operating the system have a lot to do with how failures affect cost, customer service, public safety, and the utility’s business performance.

3) Inspection, service and maintenance guidelines. Every utility has such guidelines in place along with processes that apply them.

Some if not all these guidelines, and the institutionalized habits built around them, are themselves quite old – “deteriorated” as compared to modern needs. Revision of loading and operating guidelines can reduce stress on older equipment and thus decrease the potential for failures. Modification of O&M rules and guidelines for equipment inspection and service can help find deterioration before it causes problems. There are ways to prepare and organize for contingencies so as to minimize customer inconvenience and utility cost, even when unexpected failures cannot be avoided. And, given that a utility will have to perform equipment testing, track condition, and perform pro-active refurbishment and replacement as part of a continuing condition management program...

Table of contents

• Cover Page
• Half Title
• Series Introduction
• Title Page
• Copyright Page
• Contents
• Preface
• 1 Aging Power Delivery Infrastructures
• 2 Power Delivery Systems
• 3 Customer Demand for Power and Reliability of Service
• 4 Power System Reliability and Reliability of Service
• 5 Cost and Economic Evaluation
• 6 Equipment Inspection, Testing, and Diagnostics
• 7 Aging Equipment and Its Impacts
• 8 Obsolete System Structures
• 9 Traditional Reliability Engineering Tools and Their Limitations
• 10 Primary Distribution Planning and Engineering Interactions
• 11 Equipment Condition Assessment
• 12 Optimization
• 13 Planning Methods for Aging T&D Infrastructures
• 14 Reliability Can Be Planned and Engineered
• 15 Six Aging Infrastructure Management Stories
• 16 Managing an Aging Infrastructure
• 17 Guidelines and Recommendations
• Appendix A – Notes on a Spreadsheet-Based Model for Aging Trends
• Appendix B – Sustainable Point Analysis
• Index