Why Transformers Fail By Hongzhi Ding Richard Heywood John Lapworth Simon Ryder
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WHY TRANSFORMERS FAIL Hongzhi Ding, Richard Heywood (hding@doble.com) (rheywood@doble.com) John Lapworth and Simon Ryder (jlapworth@doble.com) (sryder@doble.com ) Doble PowerTest Ltd. 5 Weyvern Park, Peasmarsh, Guildford, Surrey, GU3 1NA, United Kingdom
Abstract Knowledge from the tear down investigation of faults and failures in power transformers is of vital importance in understanding the results from the dissolved gas analysis (DGA) and electrical condition assessment measurements and preventing further incidents. This technical article discusses with examples the common failure modes observed in the scrapped power transformers. The review will also outline what we can do that is effective in preventing power transformer failures, with examples, too, showing how the developing failures could be saved through continually Transformer Asset Health Review by effective DGA analysis combining with effective condition assessment. Introduction While assisting in the investigation of unexpected transformer failures is an important aspect of the work, there are many examples of transformer component defects and faults that were detected well before an unexpected failure could occur, i.e. during routine dissolved gas analysis (DGA), electrical condition assessment and maintenance operations. Many inservice power transformers are now required to operate beyond their original design life, mainly as a consequence of missing-match between the large number of ageing transformers and the limited resources available to source replacements for them; and also because these ageing transformers are still in reasonably good working condition although their condition and ability to carry peak loads are usually unknown. As part of the transformer asset health review and life extension program, over the years Doble PowerTest have records of detailed forensic teardown inspection of more than hundred large power transformers. This involves witnessing the process of scrapping and making a thorough inspection of each component to assess its condition. This teardown of power transformers has enabled the condition assessment of components that would not normally be addressed during routine maintenance because of their inaccessibility. Knowledge of the causes of transformer in-service failures, together with assessments made during strip downs of transformers removed due to high risk exposure, have given significant insight into modes of deterioration/failure in particular design groups. This has been translated firstly into a diagnostic strategy for assessing the condition of power transformers nearing the end of their life and then integrated into asset health and asset risk reviews and finally utilized in aged transformer replacement planning. Doble PowerTest’s experiences thus far reveal most transformer failures are not due to old age, but localised damage or ageing due to some limitations in design and manufacture, application and maintenance [1-4]. Sometimes a power transformer does fail without any 2
warning notice. In most cases, however, the symptoms of developing fault and failure can be detected, prevented or eliminated. Transformer Design and Construction As electrical devices that transfer energy from one electrical circuit to another by electromagnetic coupling without moving parts, power transformers are normally regarded as highly reliable assets because they are designed and constructed by time-proven technology and materials. It is generally believed that the transformer designed and built at the turn of the 20th century was already a mature product as the essential features of the device remain unchanged to date, although the transformer continues to evolve [5, 6]. The principles that govern the function of all electrical transformers are the same regardless of size or application [5]. The typical power transformer is submerged in mineral oil for insulation and cooling and is sealed in an airtight metallic tank. Low- and high- voltage power lines lead to and from the coils through bushings. Inside the transformer tank, core and coils are packed close together to minimise electrical losses and material costs. The mineral oil coolant circulates by convection through external radiators. Figure 1 shows three winding assembly on core viewed from the HV side and after the tank being removed.
Figure 1 Three winding assemblies on core, HV side view The essential parameters that characterise the ideal transformer depend, to a large extent, on the properties of the core. The properties that are critically important in transformer core materials are permeability, saturation, resistivity and hysteresis loss. It is generally believed that it is in the core that the most significant advances in power transformer design and construction have been made [6].
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The performance of power transformers depends on dielectric insulation and cooling systems. These two systems are intimately related, because it is the amount of heat both the core and winding conductors generate that determines the permanence and durability of the insulation, and the dielectric insulation system itself is designed to service to carry off some of the heat. It is vital that the insulation utilised in a power transformer must be able to separate the different circuits; isolate the winding core and outer case from the circuits; provide mechanical support for the electrical coils and withstand the mechanical forces imposed by power system surges and short circuits. Generally Kraft paper has been utilised for winding conductor insulation, high density pressboard for inter-winding and inter-phase insulation, and crêpe paper for lead insulation. The critical properties that determine the functional life of dielectric oil/paper insulation are chemical purity, thermal stability, mechanical and dielectric strengths. What Causes a Power Transformer to Fail? It is generally believed that failure occurs when a transformer component or structure is no longer able to withstand the stresses imposed on it during operation. During the course of its life, the power transformer as a whole has been suffering the impact of thermal, mechanical, chemical, electrical and electromagnetic stresses during normal and transient loading conditions. The condition of the transformer deteriorates gradually right from the start, resulting in
Reduction in dielectric strength (i.e., the ability to withstand lightening and switching impulses); Reduction in mechanical strength (i.e., the ability to withstand any through faults); Reduction in thermal integrity of the current carrying circuit (i.e., the ability to withstand overloads); Reduction in electromagnetic integrity (i.e., the ability to transfer electromagnetic energy at specified conditions including over-excitation and overloading).
A failure ultimately occurs when the withstand strength of the transformer with respect to one of the above key properties is exceeded by operating stresses. A useful way of thinking about failure of a power transformer could be illustrated in Figure 2, as proposed by CIGRE WG 12.18 [7, 8]. In its early life of service, the power transformer has a sufficient spare safety margin between the various types of transient service stress and capability. Here “strength” and “stress” are used generically to cover any kind of incidentthermal, mechanical or electrical events. However, after a period of general ageing this may not be the case. At some point in the deterioration process, probably long before the useful life is run out, one or more parts of the transformer may well have changed just enough or even failed such that the transformer no longer performs as required, e. g. even if a transient, such as an overvoltage or close-up short circuit has been successfully withstood failure could occur at the next transient.
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Mechanisms of failure that are involved in a large transformer are often complex. Typical transformer functional failure mechanisms are summarised in Table 1, as per the CIGRE WG12.18. Note this is a functional failure model only for transformer core and coil assembly, not including on load tap changers (OLTC) and bushings. It is also important to distinguish the fault and the failure. A fault is mainly attributed to permanent and irreversible change in transformer condition. The risk of a failure occurrence depends not only on the stage of the fault developing but also the transformer functional component involved. The failure could be repairable on site, depending on the type of fault as well as the severity of the failure.
Table 1 Transformer functional failure model [7,8] System, Component
Possible Defect
Fault and Failure Mode
Dielectric system
Flashover due to:
Major insulation Minor insulation Leads insulation Electrostatic screens Mechanical system Clamping Windings Leads support Electromagnetic circuit Core Windings Structure insulation Clamping structure Magnetic shields Grounding circuit Current-carrying circuit Leads Winding conductors
Abnormal oil ageing Abnormal paper ageing Partial discharges Excessive water Oil contamination Surface contamination Loosing winding clamping Loosing winding
Circulating current Leakage flux Ageing laminations Loosing core clamping Floating potential Short-circuit (open circuit) in grounding circuit Bad joint(s) Bad contacts Contact deterioration
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Excessive paper ageing Destructive partial discharges Creeping discharges Localised surface tracking Failure of solid insulation due to:
Failure of leads support Winding displacement (radial, axial, twisting) Excessive gassing due to:
General overheating Localised overheating Arcing/sparking discharges Short-circuited turns in winding conductors Short-circuit due to:
Localised overheating
Insulation Strength
Reducing Strength with time and after incidents
Insulation Spare Margin
Failure Insulation Stress
New
Incidents
Increasing Age
Old
Figure 2 A conceptual failure model proposed by CIGRE WG 12.18 [7,8] From our records and case histories data, failures of power transformers are commonly associated with localised stress concentrations (faults), which can occur for several reasons including:
Design and manufacture weakness, e.g. poor design of conductor sizing and transpositions, poor joints, poor stress shield and shunts, poor design of clamping, inadequate local cooling, high leakage flux, poor workmanship, etc.; The microstructure of the material utilised may be defective right from the start, e.g. containing micro-voids, micro-cracks etc.; Corrosive attack of the material, e.g. sulphur corrosion on paper and conductor can also generate a local stress concentration.
Weakness in transformer design, construction and materials could be covered by low loading. However, increasing loading and extended periods of in-service usage will uncover these weaknesses. Common Failure Modes Failure modes of large power transformers are not always straightforward. But purely from an assumption of the failure experienced in a large power transformer, most transformer failures can be classified into either one or a combination of more than one of the following three modes:
Breakdown of insulation as a whole, due to severe solid insulation ageing; Breakdown of insulation by part, due to premature ageing by localised high temperature overheating; Mechanical failure of windings. 6
Common among many of the transformer failure modes is a shorted turn. The shorted turn was developed as a result of breakdown of the solid insulation which causes winding temperature shoot-up. The breakdown of solid insulation could be due to the natural wear of insulation or repeated overloading or cooling system deficiency, which often result in severe ageing of winding insulation. This type of failure (shorted turns without any prior warning or obvious system cause) is a typical ‘end of life’ failure mode. If the transformer runs abnormally hot and/or develops less than its normal out voltage, one can safely assume the possibility of shorted turns. Electrical breakdown is a common failure mode for power transformers, too. The electrical breakdown could be developed by a number of reasons such as ageing of insulation, excessive moisture content, deformed windings etc. Moisture reduces the dielectric strength of insulation and can promote the occurrence of surface creeping discharges on the pressboard barriers and lead to a flashover. Deformed windings indicate not only a high level of force that may have broken or abraded the winding conductor insulation, but also a reduction in electrical clearance. This mechanical failure of windings will then manifest itself as an electrical breakdown which actually causes failure of transformer. Poor design and overheating are very much interrelated and make for high failure modes. In the bottom end, lack of cooling causes either general or localised high temperature overheating, resulting in rapid insulation deterioration and damage progression. Breakdown of insulation between the core and main tank may lead to circulating currents in the core/frame/tank and result in local overheating. Circulating current in the tank can produce hotspots in the tank and across gasket joints, resulting in partial discharges emanation from the ground potential surfaces of the tank and parts mounted on the tank. Note local overheating in current carrying circuit, if not extremely severe, often will not itself cause direct failure of the transformer, but will reduce the mechanical strength of the insulation so that when the transformer is subjected to a system fault close to the terminals, it will then fail [5]. This is similarly true for winding movement. Poor design and loose clamping are very much interrelated and make for high failure modes, too. The most well-known design problem with loose clamping is arcing/sparking fault at the loose clamping bolts, which compromises the mechanical strength of the transformer and makes diagnosis of dielectric faults using DGA difficult. The arcing/sparking discharges also lead to deterioration of the oil and the production of fine carbon, which compromises the dielectric integrity of the transformer. Three Case Studies on Transformer Failures Case 1: Transformer Failure Due to Shorted Turns In April 2009, a 30 year old 750MVA 400/275/13kV autotransformer tripped on Buchholz. Analysis of a subsequent DGA sample from the Buchholz clearly indicated a fault. Electrical protection had shown unusual waveforms on the middle phase immediately before the trip. Condition assessment tests after the trip are shown in Table 2 (turns ratios) and Table 3 (winding resistances). Measured ratio for the middle phase differs from expected value by three times more than allowed (0.5%), indicating lost turns, and lower than expected value
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indicates the fault is in series winding. Winding resistance measurements confirm fault in the middle series winding, which was unlikely to be unlikely to be economically repairable. During the scrapping, after the wraps of the middle phase series winding were removed, the shorted turns in the 2nd and 3rd discs of series winding was found and these seemed to be particularly severe. Figure 3 shows a picture of failure by shorted turns. There was extensive loss of conductor and conductor insulation in the upper part of the series winding, which is unlikely to be economically repairable. Table 2 Turns ratios measurement on a 750MVA autotransformer after Buchholz trip Expected ratio
Applied HV-N voltage, kV A phase 0.3 12.0
1.455
1.456
Measured Ratios B phase C phase 1.452 1.435 1.455
Notes: Measurements made at 0.3 and 12 kV, using Doble M4000 Insulation Analyser and Doble TTR capacitor.
Table 3 Winding resistances on a 750MVA autotransformer after Buchholz trip Winding Series (400 to 275 kV) Common (275 kV to neutral)
A phase 0.1783 0.5236
B phase 0.3296 0.5222
Notes: Measurements made at 5A using Tinsley 5896 Transformer Microhmeter. According to WTI’s, transformer was at 15°C.
Figure 3 Failure of transformer by shorted turns 8
C phase 0.1778 0.5236
Figure 4 Comparison in colour of conductors in A/red phase series winding top disc: from left to right is outermost strand, middle strand and innermost strand The worst degree of polymerisation (DP) measurement obtained was 142/146 (average 144) from the middle strand of top disc of the middle phase series winding. The next worst result was 151/161 (average 156) from the middle strand of top disc of A/red phase series winding. The DP results on paper samples showed that apparently the insulation condition of the series winding had reached the end of its life. The DP analysis on paper samples also showed that the winding hotspot was located in the middle strand of the upper part of series winding. Figure 4 shows a visual comparison of conductors taken from A/red phase series winding top disc, from left to right is the outermost strand, middle strand and innermost strand, respectively. Note the severe discoloration of the middle strand conductor which implies not only the location of series winding hotspot, but also the inadequate cooling design in the series winding. The learning point from this case study is that the short turn was developed as a result of severe winding conductor insulation ageing which was partly a function of the age of the transformer and the loading to which it had been subjected. The thermal design of the series winding, however, led to localised overheating of certain areas, including the point of failure. Case 2: Transformer Failure Due to a Flashover In the middle of 2006, a 42 year old 30MVA 132/11kV station transformer failed releasing oil to the ground from the busting discs. It was believed the transformer might have been subjected to through fault before its failure.
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Figure 5 Failure of transformer by a flashover in the main tank
Figure 6 Close-up of the middle phase winding bottom end-blocks from HV side (left) and LV side (right) During the strip down it was found that the failure actually involved one severe arcing/sparking fault in the main tank, which was located between the bare copper strip connected to the middle phase LV winding line end and the middle phase top steel clamping platform in the LV side, where the arcing seemed to be particularly severe so that both the bare copper strip and the corner of the steel clamping platform had been damaged. Figure 5 shows a picture of failure by flashover in the main tank.
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Further inspection of the core and windings during scrapping found direct evidence of mechanical deformation of all windings from three phases particularly in middle phase. Figure 6 shows the severe displacement of the middle phase winding bottom end-blocks. Note that the missing end-blocks on the LV side had been found on the tank floor. It was therefore believed that all windings from three phases particularly the middle phase windings had been subjected to very significant circumferential forces and had significantly twisted and relaxed as a result. It was further thought that the relaxed winding clamping had caused the downward movement of the middle phase LV winding line end, which reduced electrical clearance between the bare copper strip and the steel clamping platform corner and eventually caused a flashover in main tank. The learning point from this case study is that the flashover was developed as a result of reduced electrical clearance which was due to winding mechanical deformation caused by short circuits, and poor design of having no physical support to the middle phase LV winding line lead that connected to the bus-bar. Case 3: Transformer Failure Due to Axial Collapse of Winding In late 2004 the decision was made to scrap a 50 year old 120MVA 275/132/11kV autotransformer which had suffered a serious tap changer fault. The fault was first noted during planned maintenance, and it appeared that the middle/B phase tap selector became misaligned by one tap compared with the A and C phase tap selectors. After the transformer was returned to service, the voltage control scheme eventually sent the transformer to the end of the tap range. At the end position the B phase diverter was required to switch the entire tap winding, rather than one tap step as it was designed to. This resulted in serious damage to the B phase tap changer and large currents flowing in B phase of the transformer. Fault investigation tests were made on the transformer and results of additional winding capacitance and power factor measurements are listed in Table 4. The results from B phase clearly indicated a serious problem. The large reduction in capacitance between the series and common and tap windings seemed to indicate axial collapse of the tap winding. During the strip down it was found that the transformer failed due to axial collapse of the B phase tap winding, following a fault in the B phase tap changer. This would have been impractical to repair. Figure 7 shows a picture of failure by axial collapse of the tap winding. Note there had been no serious design defects or unusual design features found during the scrapping. The transformer seemed to have no faults other than with the B phase tap winding. The degree of polymerisation analysis on paper samples were in the age 450-750, which indicates little ageing and considerable useful life remaining.
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Table 4 Fault investigation on a 120MVA autotransformer
Figure 7 Collapsed B phase tap winding
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What Can We Do That Is Effective in Preventing Transformer Failures in Our Substation? Why transformers fail is easy to understand. However, getting more transformer engineers to do their part in preventing failures is the hard part. So, what can we do that is effective in preventing transformer failures in our substations? The simple answer is that a power transformer must be replaced when it no longer meets the requirement of system reliability and before it fails [4]. In order to be able to replace the transformer before it fails, it is considered necessary to have a transformer asset health review methodology to analysis and prevent in-service failure [1-3]. This involves using information from a wide range of sources, including oil tests, on-line and off-line condition assessment tests and visual inspections. However, knowledge of transformer designs and of their strengths and weaknesses is essential to understanding the other information. Given the age of many of the transformers, such information is now in many cases only obtainable through witnessing the scrapping of transformers. The following three case examples illustrate how developing failures could be managed and even saved by effective DGA analysis combining with effective condition assessment tests. Case 4: Developing Failure Due to Loose Clamping and Leakage Flux In early 2009 a 43 year old 240MVA 275/132/13kV autotransformer was taken out of the service as per the planned replacement. This transformer had been suffering from the known loose clamping for many years, and the strip down inspection of a sister transformer one year before it was removed from the system had provided valuable information about the likely condition of this transformer believed to be significantly in risk of failure. During the scrapping it was found that approximately one third of the clamping bolts showed signs of having been loose in the past. Certain clamping bolt bosses showed signs either of spark erosion or of hammering (elongated slots). Overall the winding clamping was in a very poor condition and looks much worse than what was seen from the scrapped sister transformer a year before. The loose clamping had resulted in severe arcing/sparking discharges developing at a large number of the clamping bolts/bosses, producing fine carbon contamination everywhere particularly on the top frame surfaces. The loose clamping had also resulted in relaxed coil assembly leading to the development of partial discharges and fine carbon contaminations produced inside the windings. Figure 8 close-up shows the severe loosing clamping fault. Note how one of the missing clamping bolts had become embedded in the insulation above the tertiary winding, as shown clearly in the picture on the right hand side. Here it was electrically shielded by steel clamping ring. The same picture also shows a bent clamping bolt. During scrapping the possibly burned electrostatic shields were also noted and those seemed to be extremely severe. Figure 9 shows a picture of the copper foil having become severely overheated by the leakage flux, resulting in damage to the bottom end clamping platforms as well as to the adjacent insulation. This was not particularly apparent from dissolved gas results.
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In conclusion, the findings of the severe loose clamping plus the burned electrostatic shields provided conclusive evidence to confirm that this transformer had reached the end of its life and certainly was not capable of continuing service.
Figure 8 Loose clamping faults from LV side (left) and A phase end (right)
Figure 9 The burned electrostatic shields: general view (left) and close up (right) Case 5: Developing Failure Due to Localised Overheating In early 2009 the decision was made to scrap a 1996-made 240MVA 400/132kV (no tertiary) autotransformer, believed to be significantly in risk of failure from localised high temperature overheating in current carrying circuit. This transformer had been suffering from a thermal fault in the main tank before it was removed from service. Fitting a frame earth resistor had not stopped the development of the fault. It was believed, therefore, that the thermal fault had not been caused by a circulating current in the core/frame/tank. 14
The dissolved gas levels in the main tank had been typical of the larger transformer population until a year before the transformer was removed from the system. There was then a rapid rise in the ethylene level, accompanied by rises in the hydrogen, methane and ethane levels. The last sample before the transformer was removed from service contained 324 ppm of ethylene, 302 ppm of methane, 144 ppm of hydrogen and 123 ppm of ethane. The dissolved gas signature clearly indicates a serious thermal fault in the main tank which developed through 2008. The rate of deterioration seems to have increased during the year. The carbon monoxide level had been less than 500 ppm for much of the service years but the ratio of carbon dioxide to carbon monoxide varied between 2 and 45. These both seemed to suggest little to moderate solid insulation ageing only. However, the relative proportions of gases suggested a localised high temperature overheating fault involving solid insulation (relatively high hydrogen and methane, low acetylene, ethylene/ethane ratio < 4). Based on winding resistance measurements, it was suspected that there was likely a bad joint in the C phase LV current carrying circuit, but internal investigation inspected all joints and connections around the C phase LV terminal and there was no clear indication of any problem. It was finally concluded that the fault must be inside the C phase common winding. During scrapping, after the C phase common winding was pushed out, it was found that all joints were shown to be healthy and there was no clear indication of any problem. Figure 10 shows a picture of a developing failure point within the common winding due to localised overheating. The localised high temperature thermal fault had caused extensive loss of conductors and insulations but had not led to a short-circuited turn developing yet.
Figure 10 Developing failure point within common winding due to local overheating The learning point from this case study is that this developing failure does not seem to have been caused or exacerbated by the design of the transformer, although the root cause of the 15
thermal fault was not actually known. It could, however, be caused by any one of the following reasons: microscopic conductor damage from new; weak joint in conductor; slack damping/fretting which resulted in the loss of insulation; and a system transient. Case 6: Developing Failure in a Transformer Saved by DGA Analysis This is the case of a 750MVA 400/275/13kV autotransformer built in 1967 and currently still in service. Over the last few years this transformer has developed severe thermal fault twice but all saved by effective DGA analysis. In late 2005, the transformer was removed from service because of rapidly increasing dissolved gas results which indicated a bare metal fault inside the main tank (high ethylene as the dominant gas). The following electrical tests, including winding resistance measurements, pointed to a winding joint problem associated with the tertiary winding, most likely involving connections to the tertiary bushings. An internal inspection revealed faulty joints in the internal connection between one of the main tank tertiary bus-bars and the left hand tertiary terminal (3C2) in the tertiary loading box at the A phase end of the tank. This was originally a multi-part single aluminium bar, whereas the 3B2 and 3A2 leads were double copper busbars. The fault appeared to be due to a poorly bolted connection in the cranked part of the connection where it left the tertiary loading box to rise up towards the top of the main tank to connect to the tertiary bus-bars. As part of the repair a second parallel copper bus-bar was added to the 3C2 lead. Unfortunately, after the transformer was returned to service and tertiary loading (by a shunt reactor) resumed, further gassing was observed. Analysis of tertiary winding resistance measurements made after the 2005 repair suggested another high resistance joint problem with the 3A2 connection. During a planned outage in 2008 these resistance measurements were repeated and confirmed. After the oil was drained a visual inspection took place and a large carbon deposit was found at the base of 3A2 bushing on the joint between the flexible and the bushing.
Figure 11 Developing failure point due to local overheating: bus-bar joint in tertiary connections (left) and bushing joint (right)
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Figure 11 shows a developing failure point in the main tank due to local overheating. Note the left picture shows an overheated bus-bar joint in tertiary connections and the right picture shows overheated bushing joint.
Figure 12 Tertiary winding connections in the studied 750MVA autotransformer
Table 5 Tertiary winding resistance measurements before and after repair
Measurement (1) (2) (3) (4) (5) (6) (7)
TA to 3A2 TA to 3B2 3A2 to 3B2 3B2 to 3C2 3C2 to 3A2 TC to 3B2 TC to 3C2
Measured resistance, mΩ Before repair After repair After repair 11/6/08 3/7/08 17/7/08 21.6ºC, 41% RH 17.4ºC, 56% RH 16ºC, 89% RH 8.211 7.802 11.023 15.732 15.874 15.836 7.624 7.745 10.783 8.085 8.032 8.010 15.354 15.590 18.650 8.124 8.112 8.046 0.4281 0.4273 0.3722
Notes: Measurements made with Tinsley resistance meter
After the repair the winding resistances were measured again, and these confirmed that there were no further tertiary resistance anomalies. Note that in Figure 12, the tertiary winding connections in this transformer are somewhat unusual in that all three corners of the tertiary are brought out to the A phase end of the transformer for tertiary loading, while the original arrangement of bringing out one corner (TA and TC leads) for closing and earthing externally is retained out at the C phase end. Table 5 summarises the tertiary winding resistance measurements before and after repair.
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The learning point from this case study is that developing failures due to bad joints in main tanks of transformers could be saved just by effective DGA analysis combining with effective condition assessment tests. Conclusions Fault and failure investigations on power transformer components have an important role in improving reliability and managing the risk of transformer failure. The identification of the primary cause of failure and the subsequent analysis enable recommendations for corrective action to be made that hopefully will prevent similar failures from occurring in the future. Most unexpected power transformer failures happen because of maintenance oversights and over loadings. Couple your understanding of how power transformer components are supposed to function with a careful look at tell-tale damage, and you can prevent recurrences. When design error and/or weaknesses developing over time are uncovered, enhanced monitoring/investigation on sister units built by same manufacturer will help in preventing future failures and therefore aid in managing the risk of unexpected failure. References [1] R. Heywood, J. Lapworth, L. Hall, and Z. Richardson, “Transformer lifetime performance: Managing the risks”, 3rd IEE International Conference on Reliability of Transmission and Distribution Networks, London; February 2005. [2] R. Heywood and A. Wilson, “Managing reliability risks-Ongoing use of ageing system power transformers”, Doble Israel Conference 2007. [3] A. Wilson, R. Heywood and Z. Richardson, “The life time of power transformers”, Insucon 2006, 24-26 May 2006, Birmingham, UK. [4] H. Ding and S. Ryder, “When to replace aged transformers? Experiences from forensic tear downs and research”, Euro TechCon 2008. Liverpool, 18-20 November 2008. [5] M. J. Heathcote, J & P Transformer Book, 13th edition, Elsevier 2007. [6] J. W. Coltman, “The transformer”, IEEE Industry Applications Magazine, pp. 8-12, Jan/Feb 2002. [7] CIGRÉ Working Group 12.18, “Guide for life management techniques for power transformers”, CIGRÉ Brochure No. 227, 20 January 2003. [8] CIGRE WG 12.18 “Life management of transformers, draft interim report”, July 1999.
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