Utility Leadership Advisory: Seven Principles of Highly Effective T&D Asset Management -- Moving Toward Best Practices in Information-Based T&D Condition Assessment

Bill Cozzens | Feb 13, 2003

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Executive Summary
Energy delivery utilities are facing unprecedented challenges in terms of load growth, capacity constraints, demands for high reliability and pressure to reduce O&M expenditures and to maximize return on capital. Optimizing the cost-effective utilization of their Transmission and Distribution assets is key to resolving these challenges.

Seven Principles for Highly Effective T&D Asset Management
Through its work with utilities in North America and internationally, Software Consulting Group – a Soluziona Company – has observed that the utilities with the most effective asset management programs tend to exhibit certain common characteristics. The following table lists seven identified principles that support strong, successful asset management and why each is important.

Introduction
Effective planning, management and operation of Transmission and Distribution (T&D) assets are some of the most critical issues facing utilities in the United States. In the year 2000 the Transmission and Distribution assets of US utilities had a Net Book Value of more than $175 billion and accounted for approximately $50 billion in utility revenue.1 While T&D assets represent less than two-fifths of total utility assets and less than one-fourth of total revenues, they provide some of the most challenging operational problems and management choices facing utilities.

Transmission lines and substations provide the high capacity link between electric generating stations and the local distribution grid from which most of us receive our power. Due both to the growth in demand for power and the rapid transition to competitive wholesale power markets, transmission capacity in many regions of the country has been pushed to the limit. In addition to carrying the power required to serve each utility’s native load, the transmission system now must support long distance wheeling transactions between remote generators and power consumers. More than ever the pressure is on to operate the transmission network reliably. Unplanned transmission outages result not only in a loss of wheeling revenues but also in financial penalties imposed by the transmission operator (ISO or RTO).

While the distribution grid – the network of lower voltage primary and secondary distribution circuits and unit substations – has remained regulated, it too has been affected in unanticipated ways by deregulation and the advent of competition. In order to make themselves more attractive to investors, utilities are reducing operating expenses wherever they can and trying to maximize the return on their assets. At the same time public utility commissions in a number of states are adopting Performance Based Rates (PBR). PBR allows a utility to earn higher rates of return, but only if its performance – typically measured using indicators of energy delivery reliability, safety and quality of customer service – meets or exceeds pre-established standards. These standards can be quite rigorous. It is certainly not a foregone conclusion that utilities can meet them. The triple imperative of reducing expenses, improving return on capital and improving reliability and customer service to meet PBR requirements provides a significant challenge for most utilities.

In order to be successful – both operationally and financially – utilities providing electric transmission and distribution facilities and services must manage and utilize their assets as cost effectively as possible. Asset capital, operational and maintenance expenditures must be minimized, consistent with safe and reliable operation. This is a more complex challenge than it appears at first glance. Investment in new equipment should focus on situations where there is a clear justification for replacement of obsolete equipment, added capacity or improved performance. Similarly, when data are available to support equipment condition assessment, disciplined preventive maintenance programs should move away from rigid adherence to calendar-based schedules toward condition-based triggering of maintenance activities.

1 Source: Cambridge Energy Research Associates, “US Electric Value Chain, 2000.”

Seven Principles of Effective T&D Asset Management
Meeting this challenge: minimizing capital and maintenance expenditures while providing safe and highly reliable transmission and distribution service requires a disciplined, information-based approach to asset management decision making. Priorities for both investments in new equipment and maintenance of existing equipment should be based on good information about the performance, condition and operating environment of T&D assets. Engineering, financial and management disciplines should be brought to bear.

In working with utilities over the years – both in North America and internationally – to devise and implement work and maintenance management and asset management solutions, Software Consulting Group, a Soluziona Company, has observed that the most successful companies follow most or all of seven related practices.

This Executive Briefing will discuss these seven principles, their relationships, why they are important to an effective overall asset management program and how to move toward implementing them in your T&D asset management program.

  1. Track and Aggressively Utilize Real Time Condition and Performance Information on T&D Equipment
    Trend:
    Historically, getting any real time information on T&D equipment was impossible or extremely expensive. Some limited information was collected through the utility’s transmission SCADA system but many performance and condition indicators were not measured at all. All meters, gauges, counters, level or pressure indicators, etc. were analog and very costly to convert into a data stream that could be collected and monitored remotely.

We are seeing an increasing flow of digital information available on the condition and performance of T&D equipment. Digital sensors and instrumentation are being incorporated in more and more equipment. The data from these sensors can be delivered to us over cheaper and cheaper telecommunications links in readily decipherable packets. Cost effective and versatile real time data historian applications make the condition and performance data available for display and analysis.

This trend is only going to accelerate. With many utilities now carrying out substation automation projects that incorporate microprocessor-based relays, there are more data than many people feel they can handle. There is an increasing availability of – and orders of magnitude reduction in the cost of acquiring – real-time or near real-time data about the performance and condition of our equipment. The flow will become a flood.

Risks and Opportunities: T&D equipment is long-lived and infrequently replaced. Therefore, except in areas of new development or rapid load growth, it will be a long time before all or even a majority of equipment includes digital capability. However, many utilities are investing in upgraded transmission SCADA systems and Distribution Management Systems (DMS). Utilities have an opportunity now to begin developing experience using such real-time information in their condition-based maintenance programs. As more information becomes available in the future they will have a basis for making decisions about what data to include.

Best Practice: Real-time and near real-time information on the condition and performance of transmission and distribution equipment should be incorporated in the evaluation of equipment for maintenance. Utilities should put in place long-term strategies for using as much real-time information as can be made available. As equipment is incrementally upgraded or replaced, provisions should be made for the collection of digital information from the available sensors. Data from new sources coming about as a result of substation automation should also be included. In the meantime, load and other data from SCADA and DMS should be collected and stored in a plant historian application such as OSIsoft’s PI.

  • Collapse the Multiple “Data Silos” of T&D Asset Information
    Trend:
    Many utilities now recognize the importance of good preventive maintenance practices, especially for substation equipment. They are establishing and more or less adhering to regular periodic inspection schedules. Increasingly sophisticated diagnostic tests and analytical methods are available to detect and interpret incipient equipment problems: oil analysis, thermography, ultrasound, Doble testing, etc. Critical conditions that are found through any one of these methods can trigger an overhaul or other required maintenance. Increasingly, utilities are also using work management or maintenance management applications to plan, schedule and track maintenance work.
  • Risks and Opportunities: Historically, different sets of information about the condition, the performance and the maintenance work performed on T&D equipment have been kept in different paper files and databases. These data “silos” have been reinforced by the distinct knowledge or expertise needed to interpret different types of data and test results: It has required an expert in transformer oil analysis to decipher and interpret oil lab results. As each new type of test or evaluation procedure was added to the PM arsenal, the resulting data tended to reside in their own separate files or cubbyholes. Unless a specific lab result, reading or measurement deviated significantly from the norm and was flagged by the ‘expert’, the various results were tucked away in their respective ‘silos’ and not considered again until needed for a root cause investigation resulting from an equipment failure.

    Interrogation of the individual data ‘silos’ becomes an undesired, lengthy burden during the stressful, pressured environment of the root cause investigation. Even basic trending, much less any kind of correlation analysis, was extremely cumbersome.

    Best Practice: All information about a single piece of equipment should be uniquely identifiable and associated with that equipment, and available to all engineers and maintenance personnel responsible for evaluating and making decisions about that equipment. In principle a single unique equipment identifier should be used for all data sources related to a specific piece of equipment. In reality, since some equipment-related information describes characteristics of the location where the equipment is installed rather than the device itself, two identifiers are required – one for the device itself, the other for the location. Specific devices are installed, removed and can be moved from place to place. Therefore, the characteristics of the location are associated with the specific device, during that device’s tenure in that particular location.

    To make it widely available, equipment information should be stored on-line so it will be accessible to users in more than one location. To simplify keeping equipment information accurate and up-to-date, any information that describes multiple instances of the same equipment (for example, the manufacturer’s maintenance manual for a particular make and model circuit breaker) should be stored in one location and referenced by all the specific instances of that circuit breaker. In this way if the manufacturer issues a revised manual, replacing one record updates the information for all circuit breakers of that make and model.

  • Combine Equipment Condition, Performance, History and Criticality to Evaluate Overall Maintenance Priorities
    Trend:
    Systematically identifying the transformers, circuit breakers, or other equipment that really require maintenance is like trying to find the proverbial “needle in a haystack.” Even medium size utilities operate and maintain thousands of pieces of equipment in their transmission and distribution grids. Historically, the setting of major maintenance and capital replacement priorities has either been “by the book” – using a formulaic Preventive Maintenance schedule: “Overhaul transmission-class circuit breakers every six years.” Or such maintenance could have been haphazard or even political. If a particular maintenance division had a strong, well-connected or articulate manager, it might receive a larger capital budget allocation and be able to replace equipment that might – from an objective standpoint – not be as in need of replacement as some of the worst equipment in another division.
  • Risks and Opportunities: Equipment that really require maintenance or even deserve replacement can be missed. Other equipment may be serviced when unnecessary. With good information on the performance, condition and maintenance history of assets, it is possible to focus replacement and major maintenance such as overhauls on the most needy equipment

    Best Practice: To overcome the problem of misapplied maintenance and capital replacement, make asset condition assessment a key component of your maintenance program. Develop overall indicators of asset “health” by combining information from all available diagnostic sources. Weight the different diagnostic measures according to their importance as indicators of asset health. Past maintenance history can be treated as an additional diagnostic factor. Equipment that has required repeated corrective maintenance may be more prone to subsequent failures, so should be rated higher as candidates for replacement. Finally establish maintenance priorities by considering the importance or “criticality” of the asset. Of two identical circuit breakers with very similar diagnostic conditions, one may rate higher on the candidate list of breakers deserving maintenance or replacement because of the load it is serving (and thus it’s higher criticality.

  • Leverage Equipment Condition and Performance Information to Shape Preventive Maintenance Programs
    Trend:
    With the objective of ensuring high equipment reliability, most utilities have instituted comprehensive preventive maintenance programs. And indeed, the overall success of these programs is undeniable. Utilities pursuing these programs have seen improvements in their measures of reliability. However, these programs -- which include equipment inspections, oil sampling, Doble testing, and calendar-based periodic activities such as diagnostic testing and equipment overhauls -- consume a significant portion of most utilities’ T&D maintenance budgets.
  • Risks and Opportunities: No utility executive wants to make decisions that would unjustifiably put grid reliability at risk. The downside – whether considered from a regulatory, financial, customer satisfaction or safety standpoint – is too great. Yet many executives are concerned that they are leaving money on the table – possibly over-spending on preventive maintenance programs. “Gold plating” is the term that sometimes gets used. Many manufacturers’ maintenance recommendations are based both on time and/or use, (i.e. 5 years or 50,000 miles). The calendar component historically has been easier to implement because measures of use were not available or easily captured. For lightly or intermittently used equipment this could result in over maintenance. For heavily loaded or stressed equipment, the calendar guideline could result in under maintenance and the risk of failure. Good, integrated equipment condition and performance data in combination with information on the maintenance experience for specific equipment types and classes can be used to adjust preventive maintenance frequencies.

    Best Practice: Group equipment by peer groups (type, manufacturer, voltage class, etc.) and analyze equipment condition, performance and maintenance history for these groups. Based on condition and performance trends and historical information on maintenance performed, preventive maintenance frequencies can be adjusted. Peer groups with stable condition and performance trends and low incidence of faults requiring corrective maintenance can have their PM cycles extended. Or the work performed on particular PM cycles can be adjusted. In either case, preventive maintenance costs could be reduced significantly. In situations where maintenance requirements can be linked empirically to equipment run times (fan or compressor hours), operating cycles (breaker operations) or to some measurable equipment condition (temperature, pressure, etc.), preventive maintenance should be shifted from a calendar basis to a count or condition basis.

  • Link Condition Assessment to Work Management So Equipment Health Can Trigger Maintenance
    Trend:
    Many utilities are implementing and gaining experience with enterprise asset management (EAM) or computerized maintenance management system (CMMS) applications, frequently integrated with the company’s financial, materials management and human resource systems. These systems can provide significant benefits in terms of work budgeting, planning, prioritizing, scheduling and tracking, in optimum work force utilization and in material requisition and management.
  • Risks and Opportunities: Work management systems are used to formalize and efficiently execute the utility’s preventive and corrective maintenance programs. As implemented, they streamline and optimize work performance. However, most work management systems do not address the automated selection of the work to be performed. Preventive maintenance activities and frequencies are established outside of the work management system. Corrective work is initiated manually (user creates work order), based on detected faults or trouble situations.

    Optimization of preventive and corrective work activities occurs through the aggregation of work orders for a common circuit or work location. Recent releases of several work and maintenance management applications now allow the automated triggering of work based on detected conditions. Normal versus abnormal condition ranges can be defined and a resulting action can be specified. “If sensor temperature exceeds a particular value, then initiate a specific maintenance procedure.” These automated work-triggering capabilities are still relatively primitive. Most of the triggers do not capture the complex decision making rules that diagnosis and maintenance of complex machinery usually entails. Some can only operate based on a single parameter, rather than a combination of factors. Most do not include trends or duration measures. The fact that a sensor’s temperature exceeded a certain value, may not be as important as how long it was above that temperature or the number of times that temperature was exceeded during a given time period.

    Best Practice: Implement a software interface between condition assessment and work management, but walk before you run: Start with modest objectives. Use information collected on equipment running times or operating cycle counts to trigger routine maintenance work orders. For example, lubrication or cleaning tasks could be triggered based on motor run times – shaft bearings on transformer ventilation fans should be lubricated every 1000 hours of running time. Or count the number of times a circuit breaker operates – the breaker should be inspected or should undergo diagnostic tests if it trips more than 20 times per month. Starting with the automation of some simple count-based maintenance triggers will provide experience using an automated interface between condition assessment and work management. As maintenance engineers and managers gain experience and confidence they can move toward automating more complex maintenance decision making.

  • Develop Performance Measures for Condition Assessment and Asset Management Programs
    Trend:
    Largely due to their regulated status, utilities have historically used only the most basic financial and operational performance measures. On the financial side, the traditional emphasis has been on managing actual costs versus budget and managing O&M expense versus Capital costs. In terms of operational measures, energy delivery utilities have historically tracked aggregate measures of reliability. The most common measures have addressed total and average interruption frequency and interruption duration.
  • With the advent of deregulation and the emergence of increasing concern for financial performance, utilities have been adopting somewhat more sophisticated performance measures, both financial and non-financial. In terms of financial metrics, many utilities are now calculating business unit profitability. Some utilities have started moving toward measuring rates of return on assets, including T&D assets. Other utilities, using Activity Based Costing (ABC) techniques, have attempted to calculate their costs to provide specific energy delivery products and services, with an eye toward eventually being prepared to price these services competitively. Both of these efforts imply being able to measure or estimate the revenue that specific assets produce or contribute.

    There are also changes taking place in the areas of operational metrics. As part of the adoption of Performance Based Rates (PBR), state regulatory agencies and customer groups are also paying more attention to reliability, in many cases building performance on such measures into their PBR schemes. This can require more detailed tracking of reliability, by customer class, by geographic area within the service territory and by cause of interruption. At the same time many utilities are adopting some variety of the Balanced Scorecard, an approach to performance management that suggests performance measures should align with and support corporate strategy. In the Balanced Scorecard model, performance measures are grouped in four categories: Innovation, Process, Customer and Financial.

    Risks and Opportunities: A current challenge facing virtually every energy delivery utility is setting the appropriate performance measures and incentives around T&D services and T&D asset management. What is the utility’s T&D asset management strategy?

    How does asset management support and figure in the T&D business unit’s strategy (which in turn needs to support the utility’s overall corporate strategy)? And from a Balanced Scorecard perspective, what specific objectives and measures in the areas of Innovation, Process, Customer and Financial can best help the utility achieve its T&D asset management strategy.

    In this increasingly market-based environment, another challenge facing utilities is finding the appropriate trade-off between important operational performance measures – such as reliability – and financial performance. This requires a constant balancing act. On the one hand utilities that have strayed too far toward giving priority to financial objectives (letting preventive maintenance lag or skimping on needed system upgrades) have been punished when reliability suffered. But spending on capital or maintenance programs ignoring what is most cost-effective will adversely affect financial performance without guaranteeing high reliability.

    Best Practice: Three practices can address the challenges and opportunities inherent in developing performance measures for asset management and condition assessment.

    First, internal utility performance measures should address all phases of the asset management and asset health process. They should also include, as suggested by the Balanced Scorecard methodology, measures that assess the utility’s ability to deliver high performance asset management.

    Second, high-level aggregate or average performance measures should be disaggregated. Such disaggregation can involve breaking a measure down into its components and/or looking at a system-wide measure on a circuit-by-circuit or substation-by-substation basis.

    Third, operational and cost information should be incorporated in performance measures. By measuring and considering the actual cost of different maintenance programs and the resulting cost required to achieve specific reliability measures, decision makers will be better able to evaluate maintenance alternatives.

    Used in combination, these three practices will support the analysis of options and the evaluation of risks, costs and effectiveness of alternative approaches to achieving the utility’s asset management objectives.

  • Improve Asset Management Cost Effectively by Taking Advantage of Existing Information Technology
    Trend:
    Facing serious Y2K risks and recognizing a need to improve operational efficiency, many utilities have, over the last decade, invested heavily in new technologies – financial/ERP systems, work management, CIS/CRM, internet/intranet infrastructure, SCADA, Outage Management and GIS/AM/FM applications, among others. For many utilities at least some of these investments have paid off. Unfortunately, there have also been some bad experiences. Implementation projects that went awry or that cost much more than was originally estimated. Or applications were implemented satisfactorily but did not deliver on the expected business benefits.
  • Risks and Opportunities: The current business climate is one in which requests for major new IT investments are much less likely to be funded. Budgets are smaller. Capital is only being budgeted to those investments promising the greatest rates of return. And because of the spotty track record of major recent implementations, even promising applications are receiving much tighter scrutiny.

    Best Practice: Having made major IT infrastructure and fundamental application investments, many utilities should look for ways to get additional business benefit from these investments. What incremental additions can provide substantial additional business value? Utilities should look for opportunities to get substantial additional business value through

    1. the integration of existing applications,
    2. the creative utilization of information from other applications, and
    3. the implementation of previously unused functionality within existing applications.

    Condition assessment can be implemented by taking full advantage of many of the utility’s existing technology investments. Many utilities can leverage their SCADA, work management, local and wide area networks, and their data warehousing and reporting tools. If they have invested in a real time process historian, such as OSIsoft’s PI applications, these can be taken advantage of as well. If they do not have PI or something similar, that is a relatively small incremental investment.

    Summary
    The seven principles discussed in this paper provide a straightforward, no nonsense approach to improved asset management. Diverse information about equipment performance and condition, increasingly including real-time and near real-time data, should be consolidated and used in combination for engineering analysis to determine maintenance and capital replacement priorities. Analysis of performance, condition and maintenance history information by equipment peer groups can be used to modify and reduce the cost of preventive maintenance programs through a shift to more condition- or count-based maintenance and optimization of calendar-based PM programs. For some types of equipment and categories of maintenance, count and condition information can be used to trigger maintenance work directly. More and better-integrated information on asset conditions, performance, maintenance history and costs can also support the development of better performance measures to further improve the utility asset management program. Fortunately these principles can be implemented without huge Information Technology investments. Utilities can leverage their existing systems and sources of information with incremental investments.

    Challenges to Achieving the Vision
    Nevertheless, depending on the situation that particular utilities find themselves in, there can be significant challenges to achieving the vision embodied in these seven principles. The major challenges can be grouped into four areas.

    • Incomplete and incorrect equipment information.
    • Dynamic nature of T&D assets and the conditions to which they are subjected.
    • Unpredictability of equipment performance (and failure).
    • Business process and cultural issues.

    These challenges can seem rather daunting but there are approaches to addressing each of them. Depending on each utility’s individual circumstances and the degree to which each problem is an issue, different strategies can address the problems they face. These approaches keep the challenges from being insurmountable and keep the objective of improved asset management worthwhile.

    Conclusions
    The environment for energy delivery utilities just gets tougher and tougher! Transmission and Distribution asset managers are under pressure to maintain and even improve grid and overall energy delivery reliability without increasing O&M expenditures. Budgets for capital outlays in T&D are also restricted as utilities try to invest where they can earn the greatest return. Grid equipment is expected to operate closer to its capacity for a greater percentage of time. Capital replacements and upgrades have to focus on the most critical situations – where additional capacity is required or poorly performing equipment must be replaced. In these circumstances T&D asset managers need every potential piece of information that can be made available to them to evaluate, prioritize and plan their maintenance and capital expenditures. What we are advocating in the Seven Principles is consistent with META Group’s critical success factors for the Transmission and Distribution components of the Energy Value Chain. For both Transmission and Distribution the value discipline is excellence in operations. Critical success factors include strong asset management, performance management and a detailed understanding of costs.2 The Seven Principles provide a road map for achieving these critical success factors.

    Successfully pursuing the Seven Principles by, for example, implementing a T&D equipment condition assessment program, will have a positive impact on operational and financial performance. Bringing to light those assets that are performing poorly or are in the worst condition will enable engineering and management to provide focused attention on these assets. The risk of overlooking equipment that is performing poorly or in poor condition is substantially reduced.

    Engineering and management decisions can then be made to overhaul, repair or replace these assets. Immediate business benefits should include improved reliability and reduced capital and maintenance expenditures. While one can never eliminate the chance of equipment failure, overall reliability should improve if the worst condition equipment is receiving attention. Likewise, focus on the poorest performing and worst condition equipment will not in itself reduce capital or maintenance expenditures but it will give management confidence that capital and maintenance resources are focused on high priority items. Figure 1 illustrates the shift in costs that can be anticipated with implementation of an equipment condition assessment program.

    Figure 1. Business Benefits of T&D Equipment Condition Assessment

    2 Rick Nicholson, “Business/IT Fusion: When Crisis Becomes Opportunity,” META Group Inc. 2001, pp. 8-11.

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