An Effective Asset Management Strategy for Power Transformer Health

INTRODUCTION

A major challenge to transformer engineers of power utilities and major industries is the management of an ageing transformer fleet. Predicting transformer failure is as unpredictable as that of predicting share prices in the market. This makes it difficult to effectively plan mitigation strategies to reduce the impact of such failures. The other challenge is replacing assets too soon without getting the maximum benefit out of its useful life.

The following paper defines an asset management strategy for Power Utilities on how to manage power transformers. This becomes extremely important, especially for the effective management of an ageing fleet of transformers. Failure of critical transformers can leave a utility crippled with resultant production costs up to ten times the capital cost of equipment. The aim of this paper is to clearly map out a process to establish a risk profile of the transformer fleet and a strategy on how to mitigate such risk by incorporating effective condition monitoring techniques, design and investment strategies for the utility.

STATING THE PROBLEM 

Power transformers are one of the key components of a power circuit, especially for power utilities and heavy industries. The high capital costs involved in the purchase of a transformer means that for the best investment the replacement should be differed as late as possible or to the optimum point.

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? 

Managing your transformer fleet properly and knowing the condition of your transformers will help immensely in getting to the answers of the above questions. It is of utmost importance to have a structured approach to solving these problems. Time and human resources are limited and every transformer cannot get the same attention. It is up to the transformer engineer to formulate a system to effectively identify problem transformers for focussed attention.

YOUR TRANSFORMER FLEET

Know your Assets

 When one starts out with a large transformer fleet it can be an overwhelming task to identify which transformers need special attention or replacement. A transformer fleet at a power utility serve many applications and have varying levels of importance. The following factors play and important role in focussing the attention. These are rating, voltage levels, importance, redundancy, spares, and similar type in fleet. The first task of a transformer engineer is to record as much information on the transformer fleet as possible. Start with recording all details on the name plate of the transformer. This information must be stored in a database and forms the basis for analysis.

For , starting from a transformer fleet of 70 transformers, Figure 1 below gives an immediate picture of where most of the transformers are. The key transformers are the higher rated Generator Step-Up (GSU) and Station transformers. 

Figure 1

Identify Asset Profiles

Age Profile

Transformers no matter how well they run have a limited design life. Establish an age profile of the transformer fleet. Record the year of manufacture and take this as the reference age. Calculate the present age of the transformers and plot on a graph to give a quick picture of the age profile for the current transformer fleet.

Figure 2 

Profile the Transformer Importance

It is very important to establish what percentage of the transformer fleet are critical transformers and the impact of these transformers. Establish how many of the same type of transformers are available and number of spares. Of importance is the MVA rating, low and high voltage levels and percentage impedance. Focus must be given to the high impact transformers. For Power Utilities, these are usually GSU and station transformers and to some extent unit transformers. 

Conditioned Based Assessment

The basic approach to condition based assessment is to use the oil as the primary indicator of the internal condition of the transformer. Condition based assessment allows the transformer engineer to identify what is happening inside the transformer without the risk of going into the transformer. Insulation life is a function of thermal ageing of the system. It is reasonable to expect that the transformer insulation systems will last the expected 30-40 years at full load if the system is maintained in a good condition. Failure or end of life occurs as the result of a variety of mechanisms including poor oil preservation systems. Thus, it is necessary to examine the causes of deterioration of the paper and oil properties. This is based on dissolved gas analysis (DGA) and electrical testing.

Young identified the following as being some of the monitoring offered by the industry; winding and oil temperatures, internal partial discharge, oil moisture content, on-line DGA, tap changer monitoring, oil and air flow, external hotspots by infra red photography, pump and fan motor bearing wear [1].

Ranking the transformer according to health criteria would assist in refining the focus transformers. Transformer ageing is caused primarily from three effects. These are hydrolysis, pyrolysis and oxidation [2, 3]. It follows from here that the levels of moisture, temperature and oxygen must be controlled to within limits.

Studies on Furan compounds have provided some correlation to the degree of polymerisation and the mechanical strength of the paper insulation [4-6]. Due to paper insulation having a direct correlation to the life of a transformer, Furan results could give a rough idea of the condition of the paper without having to get a paper sample. This crude method can be used as a high level guide on the paper insulation ageing of the transformer. This method is however limited by the replacement or processing of the oil.

On can establish a rating system based on the DGA, condition of the oil and Furan levels. Dissolved gas analysis has been extensively utilised for incipient fault detection by the following methods; key gas analysis [7], the Dornenburg [8], Duval [9, 10],Rogers [11] gas ratio method and those highlighted in the ANSI/IEEE standard [12]. Use limits specific for similar transformers as each transformer would exhibit different gassing profiles according to design and materials used. The limits can be based on hydrocarbon gas limits and furan levels.

The total number of short-circuit and voltage surge 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 as an ageing factor. The clamping force of many transformers is reduced over time due to the shrinking of 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 is 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.

With the network being further strained the probability of incidents are increasing causing the ageing transformer fleet to be exposed to high number of through fault conditions. Through faults are infamous for exposing ageing and weak insulation which results in instantaneous failure of the transformer. These failures are difficult to pick up and remain a high risk for the transformer. It is thus quintessential to make sure that the transformer electrical protection is reviewed and settings appropriately set to eradicate fault conditions as soon as possible.  

FORMULATING AN ASSET MANAGEMENT STRATEGY

Lapworth and Mcgrail have highlighted the following transformer asset management strategies; replace on age, replace on failure and replace on condition [13]. The replace on age offers a low risk option but this option is capital intensive and does not allow for full utilisation of the asset. Replace on failure on the other hand makes full use of the asset but failures are at in-opportune times with risk of damage to neighbouring plant, forced outages with related penalties, and compromise of safety of personnel. The third strategy is to replace the transformer when its reliability to satisfy system requirements cannot be met anymore. This also enables for a planned replacement which allows adequate time for quality reviews and manufacture and better economic management.

Typical Life Cycle

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

Figure 3  

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 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 detail provided. If the contractor is responsible for the installation of 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 step represents the flat part of the bath tub curve. It is where the transformer operates without any major problems. Normal condition monitoring must be carried out during this phase. This includes six monthly dissolved gas sampling and analysis to identify incipient faults. This can also be supplemented by on-line DGA monitoring. The oil condition must also be monitored by routine sampling for dielectric strength, moisture and acidity. Paper condition can be monitored crudely by taking yearly Furan sampling which can be trended to establish breakdown rates. The furan levels are affected by oil processing and oil replacement which makes this method is ineffective if carried out. Routine thermal scanning of the transformer also helps in establishing localised hotspots and problems with the cooling system. This can be done three monthly.

Step 4: Inspect & Maintain

This step covers the normal routine inspection and maintenance of the transformer. Routine inspections must be carried 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, 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 of the tank.

Step 6: De-commission

Decommissioning of the transformer takes place when it is replaced or when it has faulted and cannot be reused. This includes for 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 and is 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 is composed of steps 3, 4 and 5 which consist of the longer term process of the transformer lifecycle. It is noted that over the past years due to the reliability of transformers being relatively good most of the focus had been on this phase of the lifecycle. This phase is the normal operating of the asset, maintenance with timely inspections and minor repairs to improve reliability and availability of the asset.

Phase B however comes into play when there is a need to purchase and replace a transformer either due to failure or planned replacement. This phase is made up of steps 1, 2, 6 and 7. This phase can take up to two years from compiling the specification, issuing and evaluating the tender enquiry, design, manufacture, factory acceptance, decommissioning of the old transformer, installation and commissioning of the new transformer and finally disposal of the old transformer.

Of recent years due to most of the assets reaching end of life and premature failures transformer engineers have been focusing more on procurement, design, commissioning, decommissioning and disposal of assets. Due to these activities not being everyday activities the expertise for such work is limited which result in some delays and longer down times on the plant. It is thus of utmost most importance to have a structured approach and to document and share experiences within the organisation on typical learning’s to improve the overall quality of the asset management process.

The Long Term Map

An important part of the asset management process it is to have 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 of the projects.

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 the 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

Record the design life of the transformer. This is usually taken according to history or trends in the transformer fleet, industry experience or experience of similar type of transformers in the world. For the power station transformers this was taken as 30 years. The present age of the transformer is then subtracted from this age to estimate a crude remaining life of the transformer. In the case of GSU transformers 1 and 2 this was -4 years which means that the transformer should have already been replaced. This method however does not take into account the transformer condition and only provides a guide.  The next step is to estimate the System Analysis Life

Figure 4

System Analysis Life

After carrying out condition monitoring on the transformer the transformer health is established and the remaining life is refined to establish a more accurate estimate. From the above example it is estimated that GSU transformers 1 and 2 have a remaining life of 2 and 3 years respectively after 2007. This step brings the influence of the actual condition of the transformer into consideration and provides a more accurate estimate.

Major Maintenance and Testing

It is advantageous to include all major maintenance activities on the plan so that it can be budgeted and planned for in the long term. In this example consideration is made for oil filtering, oil replacement and tan delta testing of the bushings. 

Life Extension Possibilities

After assessing the profile and replacement strategy it is prudent to explore for life extension possibilities. There are no rules to the criteria for selecting a life extension strategy but one can assess this by evaluating the remaining life and present condition around 5-10 years before the end of station life. It is important however to maintain a healthy condition of the transformer from inception. Key life extension methods would entail timely maintenance especially of the on load tap changer and bushings, reduction of oxygen and moisture levels in the transformer, removal of sludge and reduction of acidity levels, replacement of oil depending on condition, reduction of hotspot temperatures by reducing frequent overloading and through fault conditions.

Refurbishment/Replacement

This decision must be planned at least two years before the estimated end of life of the transformer. The decision for replacement or refurbishment becomes a business decision and takes into account the present condition of the tank and core, return on investment, quality of rewind companies within the country, transport costs and potential for up rating. If transformers have aged prematurely with inherent design defects it is possible to consider a redesign of the windings. This option can be more cost effective than purchasing a new transformer.

CONDITION MONITORING TOOLS

Condition monitoring techniques form an important part of the asset management strategy.  The trend is moving towards on-line methods that are non intrusive. The advantage of this is that information on the transformer condition is continuous and allows for early detection of incipient faults so that planned mitigation and recovery strategies can be put in place.

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

On-line measurement of oil and winding temperature consisting of 4-20mA analogue output are now becoming the standard. These are also transmitted to the station SCADA system. Transformer manufacturers are now starting to adopt fibre optic sensors to get direct hotspot temperatures of the windings. These also have a 4-20mA output for easy connection to data acquisition systems.  

Online moisture measurement is also fast becoming part of the condition monitoring tool. These are usually being added as supplementary to the on-line DGA equipment. These devices help to access the flow of moisture from the oil to paper to oil and establish cyclical load dependence.

Centralised data acquisition systems are the next phase to condition monitoring. It is becoming more important for manufacturers of condition monitoring equipment to focus not only on the technology of sensing key data but how this data can be effectively transmitted and analysed. International standards like IEC 61850 are assisting in the convergence of data processing and should be clearly highlighted when specifying such equipment. It is important for all this information to feed into one place where some intelligence can be built in to form automatic analysis of data. This provides the transformer engineer with more meaningful focussed information and saves time by alerting to abnormal conditions.

EXPERIENCES WITHIN THE POWER STATION

Over the last seven years the Power Station has been involved in numerous transformer projects. This consisted of 3 GSU transformer rewinds and five GSU transformer purchases. The replacement program has offered numerous opportunities for learning due to the tight project schedules and availability of plant. 

The most important part of the replacement program is to have a clear picture of what transformers need replacement. It is important to get all stakeholders involved at the start of the project. These include plant operators, maintenance and production engineers and related plant engineers. The specification and assessment of tenders is the start of a very important process in the future asset management of transformers. It is critical that a proper design review is undertaken by experienced personnel. The customer must also insist on a Factory Acceptance Test (FAT) of the transformer and ensure that the international acceptance standard IEC76 is clearly complied with.

Transformer interfaces are the highest risk areas. Careful attention needs to be paid to this aspect of the design. These interfaces consist of low and high voltage bushings connections to the plant and system busbars, cooling water interface, electrical and control interfaces to the plant, fire protection systems. Interface drawings play a key role to a successful transformer installation. It is thus important to have as built drawings when issuing a tender for a new transformer. First step is to measure and survey the site with the supplier to make sure that all interface points are clearly noted and planned for.

The logistics of a transformer replacement program must be taken into account in the overall project plan. Key aspects like oil disposal if not properly planned can eat into valuable outage time resulting in delays of the overall project schedule.    

Over the recent years a power Utility was heavily exposed to premature failures of transformers and it was evident that a reassessment was necessary in respect of the spares philosophy of critical Generator Step-up (GSU) transformers. It is recommended that an assessment is carried out on the transformer fleet to identify transformers that can be inter changed with minor modifications and holding spare transformers between such stations or transformers. 

Figure 5

The landscape is constantly changing and focus on the transformer fleet must be continuous. Figure 5 provides a picture of how the Asset profile for the GSU transformer changes in a span of ten years from 2002 to 2012.

Graph A provides the age profile at the year 2002. There were 18 GSU transformers including 2 spare transformers. There were 2 GSU transformers in the 30-40 age groups which fall under the high risk category and 14 in the 20-30 categories which are medium to high risk.

From the current transformer replacement program which started in 2003 the profile has changed to that represented in graph B. There were 2 rewinds and 3 transformer purchases with installations up to 2007. This mitigated the risk of the 2 premature aged Palmiet GSU transformers and 4 transformers from Gariep, Vanderkloof and Drakensberg Power Stations.    

Graph C provides a snapshot of the profile of the  GSU transformers in year 2012. Most of the high risk GSU transformers would have been replaced by new or rewound transformers. The 7 GSU transformers in the 30-40 age groups are the Acacia and Port Rex Gas Fired GSU transformers. Although these transformers are in this age category they are still in a satisfactory health condition and are not highly loaded with a low Station load Factor. There is also a spare transformer to reduce the impact of a transformer failure.

CONCLUSION

The following paper attempts to provide a picture of the nature of a typical transformer life cycle and the components that go into forming a transformer asset management strategy. There are numerous ways of achieving this and the author attempts to provide a structured approach for asset management decision making. Transformers are a huge investment for a Utility so it is important to balance the decision to defer the replacement/refurbishment to as late as possible and that of preventing a catastrophic failure.

The most important aspect of asset management is to know as much as you can about your assets. Then formulate techniques on achieving a focussed approach for identifying abnormal conditions and potential transformers failures.

REFERENCES

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