Transformers are key assets in a power plant. This article explores the use of mapping transformer populations to quantify the operational and economic costs due to various risk factors; including design, external and accelerated aging risks.
Generation, start-up and auxiliary transformers are typically designed for specific functions within an operating block in a power plant. The planning, manufacture and installation of custom-designed power transformers can take many years to complete. Once in operation, the premature failure of these critical assets before their expected End of Life (EOL), can be devastating to the electric utility or industrial company owner. The mapping process aids in the proactive identification of those transformers which may create the most economic and performance risk. The process helps to identify remediation, conservation and conditioning actions which ensure that these critical assets function throughout their planned lifetime.
Our January 2020 article focused on the use of the mapping process as a starting point to determine the appropriate remediation and conservation measures that your maintenance team needs to take to ensure a transformer block subjected to accelerated aging performs over the long-term. This article expands on mapping and risk assessment to identify the actions required to extend the operating lifetimes of transformers subjected to other forms of risk like design and random external risks. In cases of these risks, the mapping process generates different remediation and conservation strategies to ameliorate and control them. These strategies are then compared so that the option that best balances risks can be implemented with an evaluation of operational and financial considerations. We use a hypothetical example, based on typical field experience, to illustrate these concepts.
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Types of Risk
A transformer block is a complex system. The transformers and auxiliary equipment that comprise an operating block are interconnected and must function as designed for the block to meet operational objectives over an extended period. The issues of accelerated aging and its effect on premature failure already have been addressed in previous articles. A transformer block can also be at risk due to poor design and/or workmanship which create functional weaknesses in a transformer. These, in turn, can cascade throughout the system to cause outages, fires or other system performance issues in the transformer block. Defects such as poor welded joints or defective head gasket sealing can increase risk of failure of an individual piece of equipment or the entire transformer block. Random factors such as lightning strikes, natural disasters or short circuiting create another form of risk difficult to predict.
The term End of Life (EOL) is commonly used to describe the time at which a transformer becomes inoperable. This term is imprecise as it does not convey the actions that can be taken to reduce the risks that most affect a transformer block. These actions could include oil reconditioning and monitoring in the case of accelerated aging or creating redundancy in the system to protect from the abrupt failure of critical assets. A useful term, used in this article, is remaining substance (RS), which conveys the concept of a valuable asset that can be consumed or conserved depending on how the risks are managed. The decline in RS is exponential if the appropriate measures are not proactively taken. It is important to institute the remedial and/or conservation measures early enough so RS can be preserved in good operating condition throughout the required operating lifetime of the transformer. Field experience suggests that once RS reaches 60%, the remaining operating life of the transformer is only six years. By taking proper and timely action to manage risk factors, the transformer’s lifetime can be extended by another 10 to 15 years. The chart below depicts the trajectories of RS with and without conservation measures.
Water content measurements under 2% to greater than 3% comprise a range from which accelerated aging is measured. Proper sealing design is one means to reduce the impact of O2 on depolymerization. Partial degassing has proven to be an effective means to restore O2 levels to 30% of its saturated values.
Type 1 Failures-Age related degradation of electro-mechanical assemblies such as bushings, OLTCs and of solid insulation can contribute to transformer block failure. The risks caused by accelerated aging are quantified in the mapping process through DGA and transformer fluid testing. These testing procedures provide indications of the level of depolymerization of the solid insulation in the transformer as it cannot be measured directly. The level and rate of exposure of cellulose to aging accelerators such as high temperature, moisture, oxygen (O2) and acids are the starting points to this process. These influence the physical and electrical properties of the transformer and influence the rate of accelerated aging.
Type 1 risks are accurately determined with today’s increased sophistication of test methodologies and technologies. Once the effects of the accelerators are quantified, measures to conserve the cellulose insulation can be undertaken to extend the lifetime of the transformer. These measures include gas monitoring and oil regeneration. If managed properly, Type 1 risks can be controlled to slow age related degradation and EOL of a transformer. It is important to understand that even when the proper actions are taken, the transformer will continue to age but at a slower rate than otherwise. This means that the probability of failure from type 1 risks increases with time.
Type 2 Failures– Inadequate design or poor construction of a transformer often cause sudden EOL conditions. The inadequate design of a transformer’s cooling system creates overheating, which in turn contributes to accelerated aging and a higher probability of premature failure. Poor workmanship on welding joints results in gateways for oil leakage or the ingress of moisture and atmospheric gases into the transformer, which again cause accelerated aging leading to premature failure. Type 2 risks can develop when the poor design or poor-quality workmanship of a new transformer causes the premature failure of the transformer, resulting in significant lost revenue and repair/replacement costs. Understanding how the new equipment reacts to actual field conditions when connected to existing equipment in the block takes time.
The probability of Type 2 failures begins at a high level, but with time, it declines as the transformer is checked and adjustments are made to optimize its performance. Proper vetting can take years before the probability of failure reaches normal levels.
Type 3 Failures-External influences such as lightning or short-circuits often generate sudden and catastrophic transformer failures. The risk from a lightning strike is unquantifiable due to the uncertainty of the timing and severity of the strike. However, the short circuit of a third-party grid or station transformer also can create this type of risk. Type 3 risk is uncontrollable and random. Type 3 risks are incorporated into the mapping process by focusing on the transformers, which are most exposed to this uncertainty.
The uncertainty surrounding Type 3 failures makes them difficult to predict. As such, the cost in the event of a Type 3 failure, is often used as a proxy for the risk. These measures include lost revenue from a loss of power production over some period or the cost of buying power on the open market. Type 3 risk does not increase or decrease over time and can be thought of as a uniform probability distribution over the lifetime of the block. Type 3 failures are especially dangerous when they affect weakened assets which cause a cascade of outages to other units in the block.
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Reasons for Mapping
All transformers are exposed to various risks. They age over time causing premature failure. Their poor design can create functional weaknesses, which are only detected when operating over time. Random weather or grid related risks can cause complete transformer block shutdown. The mapping process described in this article is used to identify the risk to which a transformer block is exposed and what actions are needed to counteract the negative impact they have on performance. The process also considers the objectives of the plant owner which may include timing of plant shutdown or operating extensions, financial or safety goals. If not maintained properly, the original financial justification of the transformer and functional block in which it operates may not be reached. The final outcome of the mapping process is to provide multiple options that the plant owner can select based on an acceptable level of risk and required economic commitment.
The Mapping Process
The mapping process consists of eight steps. Each step builds on the next resulting in the evaluation of different long-term replacement, remediation and conservation actions that can be taken to reduce the risks of EOL. These action plans identify their associated costs and risks to enable the transformer block operator to select the actions best suited to meet the objectives of the plant.
The steps in the mapping process will be described using the following scenario:
In order to ensure that the transformers in a combined heat & power plant (CHP) would operate until its planned shutdown in six years, a preservation plan was developed for the plant. The initial phase of this plan was to regenerate insulating fluid for high voltage, start-up and station supply transformers. One year after the start of the preservation plan, the second phase of conditioning and conservation actions to one of the Generation Step Up Units (GSU) began when a transportable conditioning unit was installed. In the third year of the conservation process a second transportable conditioning unit was installed to further augment the conditioning of a second GSU transformer.
The data being collected from on-line gas monitoring systems over the first three years of the lifetime extension program provided a significant amount of baseline information on the trend of RS. The analysis of this data raised the possibility of a longer lifetime extension. Because of this, it was decided to augment the assessment of critical assets in the plant. The scope was changed to include the evaluation of three scenarios where the cost and risks of a longer operating period would be evaluated. The three scenarios would allow the plant owner to compare the different alternatives so that he could determine whether a further ten-year extension was feasible and, if so, which course of action would be optimal. The motivation for this broader scope was to determine if the plant could continue to generate power and heat production revenues at a reasonable cost without incurring significant operating risks.
The Mapping steps to accomplish this broader assessment of the CHP follow:
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Mapping Step 1: Statement of Objectives
Identify the life extension options available to the CHP transformer block to ensure safe and reliable operation until a scheduled extended plant shutdown in 12 years. Provide the asset owner a complete risk/reward assessment of the proposed options.
Mapping Step 2: Data Collection and Documentation
A complete history of the following data should be available and must include:
- Dissolved Gas Analysis (DGA)- The collection of historical data on the types and changing levels of certain gases is a critical phase of the mapping process.
- These oil condition measures include oil acidity, Interfacial tension (IFT), Breakdown Voltage (BVD), furan content and inhibitor content.
- Data collection of maintenance and failures must also be collected.
A key objective of this stage of the mapping process is to begin to understand the interactions of the aging accelerators and their influence on the aging process as indicated in the diagram below:
Mapping Step 3: Data Analysis
The DGA analysis at this stage provides the data from which transformer condition diagnostics and risks are identified.
Measuring oil’s aging impact on power transformers indicates the acceleration of the aging rate and the actions needed for its amelioration.
Maintenance history and data can show when and how mechanical anomalies occurred and record the mechanical design of replaced parts such as cooling systems and On Load Tap Changer (OLTC)
The table below shows the number and function of the 10 transformers in the CHP and their EOL assessment.
The data gathered in Step 2 is used to develop an understanding of the potential areas of risk and the possible replacement, remediation and conservation strategies needed to extend the life of this CHP transformer block by another 10 years.
Each transformer’s aging condition was assessed based on a number of factors derived from continuous gas monitoring and indicator trends. Remaining lifespan estimates for each transformer were made and each transformer was assigned to a Remaining Lifespan category as shown above. Other factors such as load capacity, RS and the possibility of advanced breakdown (PoAB) due to Type 2-3 risks were evaluated too.
Mapping Step 4: Risk Assessment
Transformer GSU1– This Generator Step-Up transformer shows a slightly reduced substance ranking due to a number of factors. These include higher O2 consumption and a high furan re-saturation rate which indicate some accelerated aging. Some indications of high heat in some zones suggest overloading of this transformer. Oil acidity was good. It was determined that GSU1 would need to operate with simultaneous gas conditioning to slow the O2 aging process. Estimated Remaining Lifetime is four years.
Transformer GSU2– This Generator Step Up unit is in slightly better condition than GSU1. While RS is in the same range, a leak in a diverter switch shows acetylene in the system accompanied by partial discharge. As is recommended for GSU1, GSU2 should be operated with the shared simultaneous gas conditioning unit. The Estimated Remaining Lifetime is greater than five years.
Transformer GSUOLD1– This Generator Step Up (GSU) transformer is in precarious condition. It can be used as back-up only under controlled conditions. Estimated Remaining Lifetime is less than two years.
Transformer GSUSPARE1- This transformer was acquired from a peak-load gas-fired power station. years ago. It is in excellent condition, despite its 15 years (was in operation for about 2 years). Available data are not reliable as gas samples were taken while the transformer was not operating. Inspection of its bushings show some capacitance deviations which creates fire risk. If re-testing confirms that the capacitive deviations remain and TANδ testing shows voltage leakage, it is recommended that the bushings be replaced. Estimated Remaining Lifetime is over 10 years.
Auxiliary Transformers AUX1-AUXB11- AUX 1 and 2 show some problems caused by defective tap selectors and leaky diverter switches causing high H2 levels. AUX3, AUX4, AUX5 and AUXB11 showed inconsistent readings of decreased moisture with higher BDV. This could be due to lack of data reported on these units. Estimated Remaining Lifetimes for AUX1, AUX2 and AUX3 are approximately 5 years. Estimated Remaining Lifetimes for the remaining auxiliaries are over five years.
Mapping Step 5: Classification of the units based on priority-of-importance criteria
The key transformers in the CHP (table 2) are the GSUs, GSU1 and GSU2. The redundant older GSUOLD1 has the greatest probability of not reaching the extended 10-year operating limit. Permanent deployment of the existing conditioning units will reduce the Type 1 risk of premature failure of GSUOLD1 if needed for back, up but the risk cannot be eliminated completely. The redundancy and excellent functionality of GSUSPARE1 also reduces operational risk for the GSU cohort of transformers. The acquisition of new GSUs would almost guarantee reaching the 10-year extension but may introduce Type 2 and financial risks in resale or deployment at the closing of the CHP.
The auxiliary transformers are a riskier cohort but have less impact on the operation of the CHP. The redundancy in this cohort is sufficient to minimize most risks to the entire plant. Connection of AUX1 to an external power source will further reduce the risk of losing revenue because of a decrease in the generating capacity of the plant due to premature failure.
Mapping Step 6: Preventative and Conservation Measures
The scenarios defined below are intended to reveal the different risks that may arise when replacement, remediation and conservation measures are taken:
Scenario 1– No procurement of new transformers and no access to reserve transformers for redundancy. Possibility of loss of third-party grid transformer near the CHP. This scenario is exposed to high Type 3 risk with an extensive or total breakdown of the plant due to the lack of back-up of the GSU transformers in the event of a third-party grid transformer failure. In addition, a failure of one of the GSUs would reduce revenue generation from power production by 50% as illustrated on the scenario 1 table. Heat generation revenues may also be lost.
Scenario 2– Invest in three RS conservation and conditioning systems and replace old GSU1 with a newer reserve transformer. This scenario provides back-up for the GSUs and spares for start-up and station supply auxiliary transformers. Along with the procurement of more preservation and conditioning units for the existing auxiliary transformers, Type 1 risk from their accelerated aging can be reduced so that the required 10-year extension of operating lifetime can be achieved. The switch of older GSU1 with a newer reserve will reduce some Type 1 risk. Acquire new back-up transformers for start-up and station supply for redundancy. This increases Type 2 risk which will decline over time. Also, the addition of a connection to an external grid transformer to allow supply from outside the block will reduce Type 3 risk in the case of a random risk event. This scenario is exposed to some Type 2 & 3 risks.
Scenario 3: Switch out GSU1 with a newly acquired GSU. Switch out GSU2 with GSUSPARE1. GSU2 can be used as a back-up. Acquire three back-up units for the auxiliary units. GSU1 and GSU2 can be a back-up GSU transformers for the new GSU and GSUSPARE1 which become the operating GSUs for the plant. Acquire three preservation and conditioning units to be rotated amongst the six operating auxiliary units. Replacing defective switches and bushings. This scenario is exposed to similar levels of Type 2 & 3 risks. In addition, there is some financial risk created in the event the GSU is not sold or recommissioned at the end of the ten-year extension.
Mapping Step 7: Scenario Cost Estimates and Risk Exposure
The costs and benefits for each option are summarized
Mapping Step 8: Long Term Preservation Plan
Based on the economic analysis and associated risks of each of these scenarios, Scenario 1 can be rejected outright as the benefits are offset by the level of risk in the event any one of the key assets fails. It is estimated that loss of energy production from this plant could cost up to 200,000€ per day. With a lead time of 18 months to receive a replacement transformer, this daily loss of revenue would continue to increase. As this is a CHP operation, heating revenues would also be lost during the winter months.
If Scenario 2 is selected as the long-term approach to extending the life of the CHP, both technical and economic risks will be low. The back-up units for the GSU and auxiliary transformer will minimize much of the risk in the event of a short-circuit of either a third-party grid transformer or an auxiliary start-up or supply unit. The conditioning and monitoring units will ensure RS is conserved to reduce the risk of accelerated aging in the older units.
If Scenario 3 is selected, Type 2 risks would increase but, the overall risk profile would be slightly higher than Scenario 2’s profile. Scenario 3 benefits come at a much higher investment in new equipment than Scenario 2. The higher investment also generates a financial risk if there is a significant delay in selling or recommissioning the new GSUs after the ten-year extension period.
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This article has shown how the mapping process can be used to quantify technical, economic and financial risk of transformer populations. The causes of transformer failure, e.g. poor design/workmanship, random external phenomena, and accelerated aging determine the level of uncertainty to which a transformer block is exposed. Based on the level of uncertainty and from where this uncertainty is greatest, appropriate remediation and preservation/conservation measures can be developed to ensure both technical and economic objectives are met.