Introduction

A significant challenge for transformer engineers in power utilities and major industries is managing aging transformer fleets. Predicting transformer failures is as uncertain as predicting market share prices, making it challenging to plan effective mitigation strategies. Another issue is prematurely replacing assets, missing out on maximizing their useful life. To remain competitive, utilities and industries must have the best asset management strategy for power transformers to be competitive.

This article outlines an asset management approach for Power Utilities regarding power transformer management. This is particularly crucial for efficiently handling an aging transformer fleet. Failure of essential transformers can severely impact a utility, leading to production costs up to ten times the initial equipment cost.

The article seeks to delineate a procedure for determining the risk profile of the transformer fleet and propose strategies to mitigate such risks by integrating effective condition monitoring techniques, design considerations, and investment strategies for the utility.

Stating the Problem

Power transformers represent critical components within power circuits, particularly for power utilities and heavy industries. Given the substantial capital investment required for purchasing transformers, it’s optimal to defer replacement until the latest feasible moment or at the most advantageous point to ensure the best return on investment.

Do you ask the following questions?

• How is my transformer fleet doing?
• Do I need to plan for refurbishment?
• When will a transformer fail?
• What is the risk of failure?
• Which are my high-risk transformers and how does one mitigate the risk?
• How does one determine the optimum replacement point of a transformer? 

Effectively managing your transformer fleet and understanding the condition of your transformers is crucial for addressing the above questions. It’s paramount to adopt a structured approach to tackle these challenges, considering the constraints of time and human resources. Given the limitations, not every transformer can receive equal attention. Thus, it falls upon the transformer engineer to devise a system for efficiently identifying problematic transformers that require focused attention.

Know Your Transformer Fleet

Beginning with a sizable transformer fleet can present a daunting challenge in determining which transformers require special attention or replacement. Transformer fleets within power utilities fulfill numerous applications and possess varying degrees of significance. Several factors influence the prioritization process, including rating, voltage levels, importance, redundancy, availability of spares, and similarity to other units in the fleet.

The primary responsibility of a transformer engineer is to meticulously document information on the transformer fleet, commencing with capturing all details from the transformer’s nameplate. This data is systematically stored within a database, forming the foundation for subsequent analysis.

Identify Asset Profiles

It is crucial to initially categorize the transformer fleet into distinct segments to assess their respective importance and associated risks effectively.

Rating Profile

For example, commencing with a fleet of 70 transformers, Figure 1 provides an instant overview of the distribution in terms of power rating. The pivotal transformers within this fleet are primarily the Generator Step-Up (GSU) and Station transformers, distinguished by their higher ratings.

Age Profile

Transformers, regardless of their operational efficiency, are designed with a finite lifespan. Begin by establishing an age profile of the transformer fleet. Note the year of manufacture as the reference age. Determine the current age of each transformer and plot these ages on a graph to provide a concise overview of the age distribution within the current transformer fleet.

Profile the Transformer Importance

It’s crucial to ascertain the proportion of critical transformers within the fleet and evaluate their impact. Determine the quantity of identical transformers and the availability of spare units. Key factors include the MVA rating, low and high voltage levels, and percentage impedance. Priority is allocated to high-impact transformers, which typically encompass GSU and station transformers, and to a lesser extent, unit transformers, particularly for Power Utilities. 

Condition Based Assessment

The fundamental approach to condition-based assessment relies on utilizing oil as the primary indicator of the transformer’s internal condition. This method enables the transformer engineer to discern internal conditions without the need to physically access the transformer. The lifespan of insulation is contingent upon thermal aging within the system.

Assuming the system is well-maintained, it’s reasonable to anticipate that the transformer’s insulation systems will endure the expected 30-40 years at full load. However, failure or end-of-life scenarios can arise due to various factors, including inadequate oil preservation systems. Therefore, it becomes imperative to investigate the root causes of deterioration in both paper and oil properties, typically through methods such as dissolved gas analysis (DGA) and electrical testing.

Young outlined the following monitoring options provided by the industry: monitoring of winding and oil temperatures, internal partial discharge, oil moisture content, online dissolved gas analysis (DGA), tap changer monitoring, oil, and airflow, identification of external hotspots through infrared photography, and monitoring of pump and fan motor bearing wear. [1].

Ranking transformers based on health criteria would aid in prioritizing attention to specific units. Transformer aging predominantly stems from three factors: hydrolysis, pyrolysis, and oxidation [2, 3]. Regulating the moisture, temperature, and oxygen levels within defined limits becomes important.

Research into Furan compounds has revealed a correlation between the degree of polymerization and the mechanical strength of paper insulation [4-6]. Since paper insulation significantly influences transformer lifespan, Furan compound analysis could offer a preliminary assessment of paper condition without physical sampling. While this method is a high-level guide for evaluating transformer insulation aging, its effectiveness is restricted by oil replacement or processing requirements.

A rating system can be implemented based on parameters like Dissolved Gas Analysis (DGA), the condition of the oil, and Furan levels. DGA has been widely employed for early fault detection through various methods, including key gas analysis, the Dornenburg Method, the Duval 1 Method, the Rogers Ratio Method, and those outlined in the ANSI/IEEE standard. It is crucial to set limits tailored to each transformer’s specific characteristics, as gassing profiles may vary depending on the design and materials used [7-12]. These limits can be determined based on hydrocarbon gas levels and Furan concentrations.

A total number of short circuit events also contribute to the health of the transformer. Although a transformer might have been designed and tested to withstand mechanical stress resulting from external faults, the latter must nevertheless be considered an aging factor. The clamping force of many transformers is reduced over time due to the shrinking of the insulating material. Historical data of incidents are very important and every time an incident occurs these must be recorded and the assessment of the transformer revisited.

Potential Risks

Power utility transformer fleets have remained relatively reliable over the last decade resulting in few alarms and focus by the engineer, however, it has become evident that most utilities are ending up with an ageing transformer fleet. Compounded by this is the increase in demand for electricity which results in assets being operated more at and beyond its capabilities. This has a dual effect as assets age faster and causes the probability of failure to increase.

As the network experiences increasing strain, the likelihood of incidents rises, subjecting the aging transformer fleet to many through-fault conditions. Through-faults are notorious for revealing vulnerabilities in aging and weak insulation, often leading to immediate transformer failure. These failures are challenging to detect and pose a significant risk to the transformer. Hence, it is essential for a thorough review of the transformer’s electrical protection and adjustment of settings to eliminate fault conditions. 

Formulating an Asset Management Strategy

Lapworth and McGrail have identified the following transformer asset management strategies: replacement based on age, replacement upon failure, and replacement based on condition [13]. The “replace on age” approach offers a low-risk option but is capital-intensive and does not facilitate full asset utilization.

Conversely, “replace on failure” fully utilizes the asset but entails the risk of failures occurring at inconvenient times, potentially causing damage to adjacent equipment, enforced outages with associated penalties, and jeopardizing personnel safety. The third strategy involves replacing the transformer when its reliability no longer meets system requirements. This approach allows for planned replacement, providing ample time for quality assessments, manufacturing, and improved economic management.

Typical Life Cycle

Figure 3 highlights a typical life cycle of a power transformer with seven steps.

Step 1: Specify and Manufacture

This step is where the detailed specification for the transformer is specified together with the manufacture and transport of the transformer to the site. This is a very important step as it defines the operating conditions of the transformer and it is where one has control of the internal structure of the transformer.

A bad design can mean a short lifespan of the transformer. It is highly recommended that an intense design review is conducted as a hold point. Transport is also a high-risk process and proper quality plans and checks must be in place to manage transport over sea and road.

Step 2: Install & Commission

This step introduces many risks, especially on the interface points of the transformer. These must be clearly defined and comprehensive details provided. If the contractor is responsible for installing the transformer, all scope of work must be clearly defined. The project program must include all activities and proper records must be provided for every step in the process.

Step 3: Operate

This stage represents the flat portion of the bathtub curve, indicating the smooth operation of the transformer without major issues. Regular condition monitoring is essential during this phase. This includes biannual dissolved gas sampling and analysis to detect early faults, which can be supplemented by online DGA monitoring.

Additionally, the oil condition should be monitored through routine sampling for dielectric strength, moisture, and acidity. The paper condition can be assessed roughly by annual furan sampling, although its effectiveness may be compromised by oil processing and replacement. Routine thermal scanning of the transformer, conducted every three months, aids in identifying localized hotspots and issues with the cooling system.

Step 4: Inspect & Maintain

This step covers the normal routine inspection and maintenance of the transformer. Routine inspections must be carried out monthly, especially by operating personnel. This involves visual checks on the general condition, recording of oil and winding maximum temperatures (reset max dial), tap changer readings, and general components like cooling and protection.

Maintenance also plays an important role in ensuring the good operating condition of the transformer. This includes maintenance of the tap changer, cooling fans, and pumps, and tan delta testing of bushings.  

Step 5: Repair

Small repairs are necessary to maintain the transformer life. This includes repairs to oil leaks, tap changer, fan and pump motors, and rust with repainting the tank.

Step 6: De-commission

Decommissioning the transformer occurs when it is replaced or it has faulted and cannot be reused. This includes the proper dismantling and storage in a temporary storage area. Arrangements must be made for the removal of the oil. This especially becomes a challenge when the Utility undergoes a comprehensive replacement strategy which results in hundreds of thousands of litres of oil.

Step 7: Dispose

This phase of the life cycle covers the proper removal and disposal of the transformer. Before the transformer can be scrapped a post mortem must be carried out to gain valuable experience on the mechanism of failure and weak areas. This is particularly important if there are similar transformers within the fleet.

The teardown can be done according to “IEEE Guide for Failure Investigation, Documentation, and Analysis for Power Transformers and Shunt Reactors”. This guideline provides a procedure to perform a failure analysis primarily focused on power transformers used on electric utility systems where it encourages the establishment of routine and uniform data collection procedures during the failure analysis process [14].

Phases A & B

Phase A of the life cycle comprises steps 3, 4, and 5, constituting the longer-term aspect of the transformer lifecycle. In recent years, given the relatively good reliability of transformers, much attention has been directed toward this phase of the life cycle. This phase entails the routine operation of the asset, along with maintenance, timely inspections, and minor repairs aimed at enhancing the reliability and availability of the asset.

Phase B, however, is activated when there arises a necessity to procure and replace a transformer, whether due to failure or planned replacement. This phase encompasses steps 1, 2, 6, and 7. It can extend up to two years, involving compiling specifications, issuing and assessing tender inquiries, designing, manufacturing, factory acceptance testing, decommissioning the old transformer, installing and commissioning the new transformer, and ultimately disposing of the old transformer.

In recent years, with many assets nearing their end of life and experiencing premature failures, transformer engineers have shifted their focus toward procurement, design, commissioning, decommissioning, and disposal of assets. Since these activities are not routine tasks, expertise in such areas is limited, leading to delays and extended downtimes at plants. Therefore, it is crucial to adopt a structured approach and to document and share experiences within the organization to enhance the overall quality of the asset management process.

Long Term Map

An important part of the asset management process is having a clear picture of the longer-term plan for each transformer. This map provides all time frames covering present life, remaining life, life extension possibilities, system health life, and major maintenance activities. These are defined in more detail below. This plan can then be used for the life cycle costing and financing.

Station Life

Start the process by first establishing the remaining life of the Utility, Power Station, or specific unit. This sets up the scene for future decision-making. Plot this in years starting from the present year. In figure 4 an example is made for Gariep Power Station with 2007 as the base year.

Design Life

Document the designed lifespan of the transformer, typically determined based on historical data, trends within the transformer fleet, industry expertise, or the performance of similar transformers worldwide. For power station transformers, this lifespan was established as 30 years. Subtract the current age of the transformer from this designated lifespan to approximate its remaining lifespan.

In the instance of GSU transformers 1 and 2, this calculation yielded a result of -4 years, indicating that the transformers should have been replaced already. It’s important to note that this method solely serves as a guideline and doesn’t consider the current condition of the transformer. The subsequent step involves estimating the System Analysis Life.

System Analysis Life

Following the completion of condition monitoring on the transformer, the health of the transformer is determined, and the remaining lifespan is further refined to establish a more precise estimate. Using the previous example, it is projected that GSU transformers 1 and 2 have remaining lifespans of 2 and 3 years, respectively, after 2007. This step incorporates the actual condition of the transformer, resulting in a more accurate estimation.

Major Maintenance and Testing

It is beneficial to incorporate all significant maintenance tasks into the plan to facilitate long-term budgeting and planning. In this scenario, the plan includes activities such as oil filtering, oil replacement, and tan delta testing of the bushings.

Life Extension Possibilities

After evaluating the profile and replacement strategy, it is advisable to explore possibilities for extending the life of the transformer. There are no strict criteria for selecting a life extension strategy, but one can assess this by considering the remaining life and current condition approximately 5-10 years before the end of the station life.

It is crucial, however, to maintain the transformer’s healthy condition from the beginning. Key methods for life extension would involve timely maintenance, especially of the on-load tap changer and bushings, reducing oxygen and moisture levels in the transformer, removing sludge, reducing acidity levels, replacing oil as needed, and minimizing hotspot temperatures by avoiding frequent overloading and through-fault conditions.

Refurbishment/Replacement

This decision should be made at least two years before the estimated end of life of the transformer. Whether to replace or refurbish becomes a business decision, considering factors such as the current condition of the tank and core, return on investment, availability of quality rewind companies locally, transportation expenses, and potential for uprating.

In cases where transformers have aged prematurely due to inherent design flaws, redesigning the windings could be considered. This option might be more cost-effective than acquiring a new transformer.

Condition Monitoring Tool

Condition monitoring techniques are integral to asset management strategies. There’s a shift towards non-intrusive online methods. The benefit lies in continuous monitoring, enabling early detection of potential faults in transformers. This allows for the implementation of planned mitigation and recovery strategies.

Such methods consist of online DGA which consists of equipment measuring up to eight dissolved gasses. These trends can be obtained as 4-20mA outputs or via communications linked directly to the station SCADA system for easy access.

The measurement of oil and winding temperature online with 4-20mA analog output is increasingly becoming the norm. These measurements are also integrated into the station SCADA system. Transformer manufacturers are now beginning to incorporate fiber optic sensors to directly measure hotspot temperatures of the windings. These sensors also offer a 4-20mA output, facilitating straightforward connection to data acquisition systems.

Online moisture measurement is rapidly integrating into the array of condition monitoring tools. Typically, these measurements are implemented as supplements to online DGA equipment. These devices aid in tracking the flow of moisture from oil to paper and back, establishing cyclical load dependence.

The evolution towards centralized data acquisition systems marks the next stage in condition monitoring. Manufacturers of condition monitoring equipment recognize the importance of developing sensing technology for key data focusing on effective data transmission and analysis. International standards like IEC 61850 facilitate the integration of data processing and should be emphasized when specifying such equipment.

All this information must converge into a single platform where intelligent analysis can be conducted automatically. This enables transformer engineers to access more focused and meaningful information while saving time by promptly alerting them to abnormal conditions.

Experiences

In recent years, the utility has undertaken several transformer projects. These included three GSU transformer rewinds and the acquisition of five GSU transformers. The replacement program has provided ample learning opportunities from the demanding project schedules and plant availability constraints. 

The cornerstone of any replacement program lies in gaining a comprehensive understanding of which transformers require replacement. It is vital to Engage all stakeholders at the project’s outset, including plant operators, maintenance and production engineers, and related plant personnel.

Specifying and evaluating tenders marks the commencement of a crucial process in the future asset management of transformers. Experienced personnel must conduct a thorough design review. Additionally, customers should insist on a Factory Acceptance Test (FAT) for the transformer, ensuring strict compliance with the international acceptance standard IEC76.

Transformer interfaces represent the most critical areas of risk. Thorough consideration must be given to this aspect of the design process. These interfaces encompass connections such as low and high-voltage bushings to the plant and system busbars, cooling water interfaces, electrical and control interfaces, and fire protection systems.

Interface drawings are indispensable for a successful transformer installation. Therefore, it is crucial for accurate as-built drawings when tendering for a new transformer. The initial step involves site measurement and survey in collaboration with the supplier to ensure all interface points are clearly identified and adequately planned.

The logistics of a transformer replacement program should be carefully considered within the comprehensive project plan. Critical factors such as oil disposal, can consume valuable outage time, leading to delays in the overall project timeline.  

In recent years, power utilities experienced significant vulnerability to premature transformer failures, highlighting the need to reassess the spare parts strategy for critical Generator Step-up (GSU) transformers. It is advised to evaluate the transformer fleet to identify units that can be exchanged with minor plant modification and to maintain spare transformers between such stations or transformers.

Graph C offers an overview of the GSU transformers’ status in 2012. By that time, the majority of high-risk GSU transformers had likely been substituted with new units or undergone rewinding. Among the seven GSU transformers within the 30-40 age bracket these GSU transformers remain in satisfactory health and experience low loading, indicated by a low Station Load Factor. Additionally, a spare transformer is available to mitigate the consequences of a potential transformer failure.

Conclusion

This article outlines the typical life cycle of a power transformer and the key elements involved in developing an effective asset management strategy. There are various methods to accomplish this, and the author endeavors to provide a systematic approach to decision-making in asset management. Transformers represent a significant investment for utilities and major industries. It is crucial to strike a balance between delaying replacement or refurbishment as long as feasible and preventing potential catastrophic failures.

An asset management program’s most important aspect is knowing as much as possible about your assets. Then formulate techniques for achieving a focussed approach for identifying abnormal conditions and potential transformer failures.

References

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