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Asset-Management of Transformers Based on Condition Monitoring and Standard Diagnosis Key Words: asset management, condition monitoring, diagnosis, international test standard, transformerdynamics, space environment, printed circuit boards, homocharge, heterocharge Introduction

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nder present deregulation policies of electric power sys tems, every utility is trying to cut its costs, while being acutely aware that the prevention of accidental loss is more important than ever; for example, the capital loss of an accidental outage is often counted in millions of dollars for transformers. To meet the growing demand of the electric power grid and to maintain system reliability, significant changes may be required in the way a utility operates and cares for its transformers. It is usually not economically feasible to subject every aging transformer to rigorous inspection and extensive testing. A promising industry strategy for life-cycle management is to set monitoring priorities and to provide strategic maintenances for all transformers. This is the reason why monitoring, analyzing, or diagnostic systems have become an essential part of the supervision of transformers. With the help of measuring techniques, technical diagnostics permit a standard evaluation, which goes beyond summarizing the obvious signs of defects. Different monitoring methods that cover a multiplicity of physical effects are used; from the measurement of the parameters; to the analysis of data and diagnosis of failure; and lastly to electrical, thermal, mechanical, and optical techniques. Therefore, the aims of the diagnostic methods are the evaluation of the operating conditions, finding the causes of aging, recommending measures to improve quality, and the assessment of lifetime. With these technical diagnostic methods it is possible to record typical values from which conclusions can be drawn about the future operational behavior of transformers. The operating conditions of transformers are the important inputs to the technical and economic models used to determine the most cost-effective alternative for operation, refurbishment, or replacement.

Failure Survey on Transformers There are many different risk assessment methods and strategies available to the utility industry for a large family of trans-

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Xiang Zhang and Ernst Gockenbach Institute of Electric Power Systems, Department of High Voltage Engineering, Schering Institut, Leibniz Universität Hannover, Germany

The important aim of the standardization is to develop the multiple diagnostic models that combine results from the different tests and give an overall assessment of reliability and maintenance for transformers.

formers. The risk-based FMEA process (failure mode and effect analysis) uses expert systems to identify and prioritize the highest risk for transformers. There are a number of failure mechanisms which affect the life expectancy of transformers, and transformer failure can occur as a result of different causes and conditions (Figure 1). Failure factors in transformers include electrical breakdown, lightning, dielectric fault, loose connection, incorrect maintenance, moisture, excessive overloading, and other causes [1]. Contamination, thermal aging, repetitive excessive voltage stress, and mechanical deformation hasten electrical breakdown. Dielectric failure is a common failure occurrence and can have a profound effect on

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Figure. 1. Transformer failure causes [1].

useful life. Contamination and thermal aging can be monitored through testing. Voltage stress can be controlled by design of the transformer protection and operating philosophy. Figure 2 illustrates the failure statistics of the defective components and identifies those areas where failure-reducing efforts can be best directed. When analyzing the failure causes, information on faults is given in load tap changer (LTC), bushing, winding, tank, core, and relay [2]. Figure 3 shows the most common detection methods of transformer failures and the percentage of all the detection methods representing studies conducted for many years: relay test, inspection, turns ratio test (TTR), dissolved gas analysis (DGA), resistance test, total combustible gas test (TCG), current test, power factor test, temperature test, capacitance test [3]. In the following, we will discuss the diagnostic methods. Once the FMEA process has established a priority list, diagnostic testing and condition assessment can establish a detailed asset management strategy. The importance of diagnostic methods can recognize which diagnostic parameter affects the transformer condition to a greater or lesser degree than other parameters [4]. Transformer diagnostics are somewhat subjective, relying on (1) analysis of oil and paper; (2) power factor, capacitance, and excitation current tests; (3) turns ratio, leakage reactance, winding resistance, frequency response, core insulation resistance, ultrasonic/sonic, and vibration analysis. Figure 4 ranks the importance of different diagnostic methods for the estimation of transformer conditions.

Figure 2. Defective components of a transformer (LTC: load tap changer) [2].

July/August 2008 — Vol. 24, No.4

Figure 3. Transformer failure detection methods (TTR: transformer turns ratio; DGA: dissolved gas analysis; TCG: total combustible gas; PD: partial discharge) [3].

Condition Monitoring and Standard Diagnosis One of the most important tasks for utilities is the maintenance of transformers to provide high customer reliability. There are some basic procedures by which a utility can better judge the condition of its transformers: monitoring, diagnosis, and maintenance. These basic evaluation steps in condition assessment provide the data for analysis and prioritization of maintenance measures. For effective maintenance, testing and diagnostics must be applied in a careful coordinated way that uses the results from international testing standards to identify overall transformer condition and performance. The results of these investigations are important

Figure 4. The importance of different diagnostic methods to estimate transformer conditions with color distinction.

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Table 1. DGA Analysis Limit 1. Four IEEE® Conditions 2. Duval Triangle Analysis 3. Rogers Ratio Analysis 4. Doernenberg Ratio Analysis

Diagnostics The measured parameters < recommended safety limits: The most severe intensity of energy dissipation occurs with arcing, less with heating, and least with corona.

Interpretation

Measures

1. Overheating destroys oil insulation and reduces life expectancy of transformers. 2. The quality of oil is reflective of the health of transformers.

1. The different measures are made according to conditions of transformers. 2. Internal inspection should be considered.

Table 2. Typical Faults and Possible Findings in Transformers Fault types

Possible findings

Partial discharge

Weakened insulation from aging and electrical stress.

Discharge of low energy

1. Pinhole punctures in paper insulation with carbon and carbon tracking. 2. Possible carbon particles in oil. 3. Possible carbon particles in oil. 4. Possible loose shield, poor grounding of metal objects.

Discharge of high energy

1. Metal fusion, poor contacts in LTC or lead connections. 2. Weakened insulation from aging and electrical stress. Carbonized oil. 3. Paper destruction if it is in the arc path or overheated.

Thermal fault < 300°C

1. Discoloration of paper insulation. 2. Overloading and/or cooling problem. 3. Bad connection in leads or LTC. 4. Stray current path and/or stray magnetic flux.

Thermal fault 300°C–700°C

1. Paper insulation destroyed. 2. Oil heavily carbonized.

Thermal fault > 700°C

1. Same as above with metal discoloration. 2. Arcing may have caused a thermal fault.

to determine the most cost-effective alternative for operation, refurbishment, or replacement. To reliably assess the overall condition of a transformer, several monitoring techniques are used or are under investigation. In addition to the traditional routine tests, there are some specialized tests including partial discharge measurement, frequency response analysis, infrared examination, vibration analysis, and degree of polymerization. These monitoring tests may detect problems such as local partial discharge, winding looseness and displacement, mechanical faults, hot spot at connectors, moisture in paper and aging of paper, as well as insulation degradation. The careful recording and plotting of the test results makes it possible to get the full information out of a test and to compare the values with those of previously accomplished tests and international testing standards. Interpretive discussions are also included to provide guidance on acceptance criteria. These activities may help identify existing weaknesses or faults and also give some indication of expected service reliability and remaining life.

electrical or thermal stresses break down to liberate small quantities of gases. The composition of these gases is dependent upon the type of fault (Tables 1 and 2). The most important diagnostic parameters are the individual and total dissolved combustible gas

A. Dissolved Gas Analysis (DGA) DGA has proven to be a valuable and reliable diagnostic technique for the detection of incipient fault conditions within liquid-immersed transformers. Insulating oils under abnormal 28

Figure 5. Duval Triangle Analysis for DGA [6].


Figure 6. Roger Ratio Criteria for DGA [7].

concentrations (TDCG) and their generation rates [5]. By means of dissolved gas analysis (DGA), it is possible to distinguish fault types such as internal arcing, bad electrical contacts, hot spots, partial discharge, or overheating in oil, cellulose paper, tank, or conductors, etc.

The first step is to establish whether or not a fault exists by using the IEEE method [5]. Only when these levels exceed some threshold value is a fault suspected. The second step is to determine the type of fault. Three methods are most commonly used: Duval Triangle (Figure 5), Roger Ratio Criteria (Figure 6) and

Table 3. Moisture Test of Oil Limit

Diagnostics

Interpretation

Measures

M/DW (moisture/dry weight) > 2.5%

1. Moisture in presence of oxygen is extremely hazardous to insulation of paper and transformer. 2. Moisture and oxygen form acids, metal soaps and sludge, causing transformer cooling to be less efficient, temperature to rise slowly over time and paper insulation to decay. 3. Moisture reduces the dielectric strength of oil. 4. Above 4% M/DW, it is in danger of flashover if temperature rises to 90°C.

1. Paper insulation has a much greater affinity for water than oil does. 2. Temperature is also a big factor in how water distributes itself between the oil and paper. 3. Each time the moisture is doubled in a transformer, the life of insulation is cut by one-half. 4. This is a vicious cycle of increasing speed with deterioration forming more acid and causing more decay.

1. Transformer should have a dry out with vacuum or do round-the-clock recirculation with a Bowser. 2. DGA and Doble tests should be examined.

Table 4. IFT Test of Oil Limit

Diagnostics

Interpretation

Measures

Number of interfacial tension < 22 dynes/cm

1. Oil is very contaminated and sludge is formed. 2. Sludge will settle on windings, insulation, cooling surfaces, and cause loading and cooling problem. This will greatly shorten transformer life.

1. As oil ages, it is contaminated by oxidation products of oil and paper insulation. These oxidation products will weaken the surface tension between oil and water and lower IFT number. 2. IFT and acid number together are an excellent indication of when oil needs to be reclaimed.

Oil should be reclaimed to prevent sludge when it reaches 25 dynes/cm.


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Table 5. Oxygen Test of Oil Limit

Diagnostics

Interpretation

Measures

O2 concentration > 2000 ppm

1. High oxygen means a leakage in conservator. 2. Oxygen in oil greatly accelerates paper deterioration.

1. Under the same temperature conditions, cellulose insulation in highoxygen oil will last 10 times shorter than insulation in low-oxygen oil. 2. This becomes even more critical with moisture above safe level.

1. Oil should be de-gassed and new oxygen inhibitor installed when oxygen reaches 10000 ppm. 2. DGA test must be done.

Ditertiary Butyl Paracresol by total weight of oil > 0.3%

1. Inhibitor is used up. 2. Transformer ages.

1. Oxygen inhibitor is a key to extend the life of transformers. 2. This works similarly to a sacrificial anode in grounding circuits. Oxygen attacks inhibitor instead of cellulose insulation.

1. Inhibitor needs to be replaced. 2. Oil needs to be treated. 3. DGA test must be done.

Table 6. Acid Test of Oil Limit

Diagnostics

Interpretation

Measures

Acid number > 0.4 mg KOH/gm

1. Oxidation of insulation and oil form acids and sludge. 2. Sludge will settle on windings, insulation, cooling surfaces and cause loading and cooling problems as temperature rises slowly. This will greatly shorten transformer life.

1. Acid attacks metals in tank and forms soaps. Acid also attacks cellulose and accelerates insulation degradation. 2. IFT and acid number together are an excellent indication of when oil needs to be reclaimed.

Oil should be reclaimed to prevent sludge when it reaches 0.2 mg KOH/gm.

Table 7. Power Factor Test of Oil Limit

Diagnostics

Interpretation

Measures

Power factor > 1.0% (25 °C)

1. The insulation integrity of oil may be broken down. 2. The state of humidity of oil is determined. 3. Transformer failure is imminent when the power factor is above 2%.

1. The dielectric loss indicates deterioration or contamination of oil from by-products such as water, carbon, or other conducting particles, including metal soaps and oxidation products. 2. A trend can be established as insulation system ages. 3. Test values are compared to previous or factory tests.

1. Replacement or reclaiming of oil is required immediately. 2. Internal inspection should be considered before re-energized. 3. Above 2%, oil should be removed from service and replaced because oil cannot be longer reclaimed.

Table 8. Dielectric Strength Test of Oil

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Limit

Diagnostics

Interpretation

Measures

1. Minimum oil breakdown voltage < 20kV (for rated voltage < 288kV) 2. Minimum oil breakdown voltage 250 ppb

1. Overheating, lightning, oxidation, acids and high moisture accelerate the destruction of cellulose insulation and form furanic compounds. 2. Paper insulation is being deteriorated and transformer life reduced at a high rate.

1. Furan is especially helpful in estimating remaining life in paper insulation and transformer life. 2. Test values are compared to previous or factory tests.

1. Oil should be reclaimed. 2. Use in conjunction with IFT and acid number. 3. DGA is always required.


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Table 10. DP Test of Cellulose Paper Limit

Diagnostics

Interpretation

Measures

Degree of polymerization < 200 DP

All mechanical strength of cellulose insulation has been lost and paper insulation has reached the end of life.

1. The cellulose molecule is made up of a long chain of glucose rings which form the mechanical strength of molecule and paper. DP is the average number of these rings in molecule. As paper ages or deteriorates from heat, acids, oxygen, and water; bonds between the rings begin to break, DP decreases. 2. DP is the most dependable means of determining paper deterioration and remaining life.

1. Transformer must be replaced. 2. Internal inspection is required.

Table 11. CO2/CO Ratio Test of Cellulose Paper Limit

Diagnostics

Interpretation

Measures

CO2/CO < 3

1. Imminent danger of failure. 2. Severe and rapid deterioration of cellulose is certainly occurring. 3. The fault is probably caused by a bad connection on a bushing base or on LTC, or a problem with a core ground. 4. An excellent indication of abnormally high temperatures and rapidly deteriorating cellulose insulation is a CO2/CO 0.5 % (20 °C)

1. The insulation integrity of windings, bushings, and insulation systems may be lost. 2. The state of humidity of oil is determined. 3. Transformer failure is imminent when the power factor is above 2%.

1. The dielectric loss indicates deterioration or contamination of insulation systems from by-products such as water, carbon, or other conducting particles. 2. A trend can be established as insulation system ages. 3. Test values are compared to previous or factory tests.

1. Internal inspection should be considered before re-energized. 2. If the problem is severe, the unit may have to be taken out of service.

the need for an internal inspection. This information supplements DGA if DGA shows the generation of heat gases. When comparing to factory tests, a temperature correction must be employed.

N. Ultrasonic and Sonic Fault Detection Tests Partial discharge occurs in an insulating system when a local breakdown of the insulating medium causes a redistribution of charge within the insulating system [9], [22]. There may also be changes to the original impulse (electrical, mechanical, acoustical, and optical) due to the propagation characteristics in the insulating medium. The PD measurement systems principally depend on the bandwidth (narrow-, limited-wide, or wide-band system). With the knowledge of the impulse characteristic (spectrum and waveform of the PD impulse) different measurement methods for the apparent charge and the localization of failure are possible. One technique consists of electrical measurements in millivolts, picocoulombs, or in microvolts of radio frequency. The other method consists of acoustical measurements with an ultrasonic transducer. The diagnostic procedure is based on the evaluation of the signal deformation of PD pulses within the transformer by mathematical algorithms. Figure 14 describes schematically the localization of failure in a transformer winding which is based on the comparison of the winding model with the transfer function measured on the real transformer winding.

This test can detect partial discharge (corona) and full discharge (arcing) inside the transformer (Table 22). These devices also can detect loose parts inside the transformer that cause corona, sparking, and arcing. Sonic testing can detect increased core or coil noise (looseness) and vibration, failing bearings in oil pumps and fans, and nitrogen leaks in nitrogen-blanketed transformers. Information gained from these measurements supplements DGA testing, and provides additional support information for de-energized tests such as core ground and winding resistance tests.

O. Visible Inspection and Internal Inspection If an internal inspection is absolutely necessary, it must be completed by an experienced person who knows exactly what to look for and where to look. There are very few reasons for a visible inspection or an internal inspection as shown below [9]: • corona in bushings, arresters, and all high voltage connections • incorrect mechanical connections in conservator, bladder, breather, etc. • increasing C2H2, C2H4, and C2H6 in DGA tests • an additional core ground • loose windings • low CO2/CO ratio • high furans

Figure 13: Aging behavior of resin-bonded paper bushings [17].


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Table 14. Capacitance Test Limit

Diagnostics

Interpretation

Measures

Changes in capacitances

1. Bushing loss and moisture ingress. 2. Winding deformation, displaced wedging and winding support as some events occur, such as near-by lightning strikes or through faults.

1. A trend can be established as insulation system ages. 2. Test values are compared to previous or factory tests.

1. The test results are evidenced also by an increasing power factor. 2. Internal inspection should be considered before re-energized. 3. If the problem is severe, the unit may have to be taken out of service.

Table 15. Excitation current test Limit

Diagnostics

Interpretation

Measures

1. Difference between two phaseexcitation currents >5% for a rated excitation current < 50mA 2. Difference between two phaseexcitation currents >10% for a rated excitation current ≥ 50mA

1. There are short-circuited turns, poor electrical connections, core delaminations, core lamination shorts, and LTC problems. 2. There is an internal problem if the measured value > these limits.

1. When poor electrical connections occur, the reluctance through the magnetic core changes, resulting in a change in the measured excitation current. 2. The excitation current test relies on reluctance of core. 3. A trend can be established as insulation system ages. 4. Test values are compared to previous or factory tests.

1. Other tests should also show abnormalities; 2. Internal inspection should be considered before re-energized. 3. If the problem is severe, the unit may have to be taken out of service.

Table 16. Frequency response analysis Limit

Diagnostics

Interpretation

Measures

Shape change >3dB

1. There is winding displacement or damage if frequency >10000Hz. 2. There is core movement or damage if frequency 0.5%

1. False turns ratio indicates the shorted turns which may result from short circuits, open circuits, or insulation failures for service-aged transformers. 2. This value is above 0.1% for new transformers.

Test values are compared to previous or factory tests.

1. Set the tap changer position on which the nameplate voltage is based. 2. Nameplate information for reclamation transformers is based on the tap 3 position of the tap changer. 3. DGA and Doble tests have been performed.

Table 19. Leakage reactance test Limit

Diagnostics

Interpretation

Measures

Difference from the nameplate Impedance: > 3%

1. These changes in impedance indicate winding deformation, displaced wedging and winding support as some events occur, such as near-by lightning strikes, through faults, or other surges. 2. Winding deformation can lead to immediate transformer failure after a severe through fault or a small deformation can lead to a failure years later.

1. When winding distortion occurs, the reluctance to the magnetic flux changes, resulting in a change in the measured leakage reactance. 2. The leakage reactance test relies on reluctance of spaces. 3. A trend can be established as transformers age. 4. Test values are compared to previous or factory tests.

1. This test complements capacitance and excitation current tests and they are used together. 2. Internal inspection should be considered before re-energized. 3. If the problem is severe, the unit may have to be taken out of service.

Table 20. Core-to-ground resistance test Limit

Diagnostics

Interpretation

Measures

Resistance >1000 MΩ

A new transformer.

A trend can be established as insulation system ages.

Resistance > 100 MΩ

A service-aged transformer.

Resistance 10-100MΩ

Deteriorating insulation between core and ground.

1. The unintentional core ground must be corrected before energizing if below 10 MΩ. 2. This test is necessary if C2H4, C2H6, and CH4 are present by DGA test and all connections are good by winding resistance test.

Resistance < 10 MΩ

It is sufficient to cause destructive circulating currents.

Table 21. Winding resistance test Limit

Diagnostics

Interpretation

Measures

Resistance change to the factory value > 5%

1. Loose connections on bushing, LTC, and arrester may be detected. 2. Shorted winding turns or open winding circuit.

Test values are compared to previous or factory tests with the same reference temperature.

1. This test is necessary if C2H4, C2H6, and CH4 are present by DGA test. 2. Turns ratio, frequency response, and Doble tests may indicate that this test is necessary.


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Figure 14. Fault location in a transformer winding [14].

Asset Management of Transformer Asset management of transformers has gained an increasing acceptance in the past 15 to 20 years, due to economic and technical reasons. The fundamental objective is to prolong the possible service life and to minimize operating costs. Operation, maintenance, and refurbishment of a transformer must all be considered together to determine the whole life-cycle cost for the transformer. The lifetime of a transformer is affected by the decrease in electrical, thermal, or mechanical strength, related to the aging of windings, tanks, bushings, or load tap changers. The aging of windings depends strongly on the operating history of the transformer, particularly on the thermal stress due to an overload. Tanks are affected by corrosion which is related to operating time and maintenance history. The aging of bushings due to thermal stress depends on the operating load of the transformer. During the normal operation of load tap changers, the operating reliability is affected by the particles produced in insulating oils corresponding to the temperature as well as to the operating frequency.

In oil-impregnated transformers, much attention has been paid to the condition diagnosis of the cellulose insulating materials (paper and pressboard). The insulating paper around the conductors decays if it has been aged due to the heat dissipation of windings, the loss induced by eddy-current, or the presence of water. Thus, the effects of temperature and water on the lifetime of insulating paper should be taken into consideration. Furthermore, load tap changers are aged by charged particles existing in insulating materials. If the electrical stress continues for a long time, partial discharges produce so much decomposition that conductive paths are formed in dielectric materials and the dielectric strength of insulating materials tends to decrease with time. The decrease of mechanical strength is the main cause of failures. Transformers are aged typically due to wear-out processes such as material fatigue under cyclic loading. This may occur when normal vibration causes failure or during the more severe forces of through-fault conditions. When mechanical stress is present, an empirical model based on a fatigue crack propagation approach can be described.

Table 22. Ultrasonic and Sonic Fault Detection Tests

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Limit

Diagnostics

Interpretation

Measures

Frequency: Audible

1. Partial discharges most often occur near the top of transformer in areas of high voltage stress which can readily be located. 2. Partial discharges located deep within windings may not be sensitive enough to detect and locate. 3. Loose parts inside transformer can be located through the test. 4. Sonic (audible ranges) fault detection can find mechanical problems such as noisy bearings, gas leaks, or other loose parts.

1. Low energy discharges from partial discharge (corona) or full discharge (arcing) emit energy in the order 20 kHz to 200 kHz. These frequencies are above levels that can be detected audibly. 2. Remedying these defects can sometimes extend transformer service life. 3. Test values are compared to previous or factory tests.

1. This test should be applied when H2 in DGA test increasing markedly. CH4, C2H4, C2H6, and C2H2 may also be increasing. 2. Internal inspection should be considered. 3. This defect can be easily remedied.


References

Figure 15. Calculated failure probabilities: transmission transformer (solid line); distribution transformer (dotted line).

Therefore, the failure probability of transformers (P(t)) can be well described by the diagnostic model [23] P(t) = f(E,M,T,t) where E, M, T, and t are the electrical, mechanical, thermal stresses, and lifetime, respectively. Figure 15 shows the cumulative probability distribution of failure for transmission and distribution transformers which have the obvious dependence on component age. Transmission transformers cause primary failures in electric power systems, thus they are very maintenance-relevant. For transmission transformers, the decrease of mechanical strength is the most frequent cause of failure, also yielding to the leakage of oil or the damage of metal shells to a large extent. As significant equipment, distribution transformers are affected in three ways by the degradation stress: leakage of oil, abnormal operation of on-load tap changers, and accidental voltage impulse on transformers.

Conclusions In this paper, a methodology is developed to use data acquisition derived from condition monitoring and standard diagnosis for rehabilitation purposes of transformers. The interpretation and understanding of the test data are obtained from international test standards to determine the current condition of transformers. In an attempt to ascertain monitoring priorities, the effective test methods are selected for transformer diagnosis. In particular, the standardization of diagnostic and analytical techniques are being improved that will enable field personnel to more easily use the test results and will reduce the need for interpretation by experts. In addition, the advanced method has the potential to reduce the time greatly and increase the accuracy of diagnostics. The important aim of the standardization is to develop the multiple diagnostic models that combine results from the different tests and give an overall assessment of reliability and maintenance for transformers.


[1] R. James and W. Bartley, “Transformer asset management,” Weidmann – ACTI Inc. Second Annual Conference, New Diagnostic Concepts for Better Asset Management, Nov. 2003. [2] CIGRE Working Group 12.05, “An international survey on failures in large power transformers in service,” Electra, no. 88, pp. 21–47, 1983. [3] Doble Client Committee on Transformers, “Analysis of replies to the technical questionnaire on power transformer failures and troubles,” Proceedings of the 65th Annual International Conference of Doble Clients, pp. 8-2.1–8-2.10, 1998. [4] IEEE Guide for the Evaluation and Reconditioning of Liquid Immersed Power Transformers, IEEE Std. C57.140, 2006. [5] IEEE Guide for the Interpretation of Gases Generated in OilImmersed Transformer, IEEE C57.104, 2007. [6] M. Duval, “Dissolved gas analysis: It can save your transformer,” IEEE Electr. Insul. Mag., vol. 5, no. 6, pp. 22–27, 1989. [7] IEC Std 60599, 1999, Mineral Oil-Impregnated Electrical Equipment in Service - Guide to the Interpretation of Dissolved and Free Gases Analysis. [8] IEEE Std. 637, 2007, IEEE Guide for the Reclamation of Insulating Oil and Criteria for Its Use. [9] IEEE Std. 62, 1995, IEEE Guide for Diagnostic Field Testing of Electric Power Apparatus - Part 1: Oil Filled Power Transformers, Regulators, and Reactors. [10] IEEE C57.106, 2006, IEEE Guide for Acceptance and Maintenance of Insulating Oil in Equipment. [11] Y. Du, M. Zahn, B. C. Lesieutre, and A. V. Mamishev, “Moisture equilibrium in transformer paper-oil systems,” IEEE Electr. Insul. Mag., vol. 15, no. 1, pp. 11–20, 1999. [12] J. Fitch, “The surface tension test - Is it worth resurrecting?,” Pract. Oil Anal. Mag., Sept. 2002 [13] P. Thomas and A. K. Shukla Raghuveer, “Aging studies on paper - oil to assess the condition of solid insulation used in power transformers,” IEEE 7th Int. Conf. Solid Dielectrics, Eindhoven, the Netherlands, 2001. [14] H. Borsi and E. Gockenbach, “Monitoring, diagnosis and life management of power transformers”, Conf. Maintenance Operation High-Voltage Electrical Equipment, (TechCon Asia-Pacific), Sydney, Australia, May 2007. [15] IEEE Std. C57.91, 2002, IEEE Guide for Loading Mineral-OilImmersed Transformers. [16] Z. Korendo and M. Florkowski, “Thermography-based diagnostics of power equipment,” Power Eng. J., pp. 33–42, Feb. 2001. [17] J. Schneider, A. J. Gaul, C. Neumann, J. Hograefer, W. Wellßow, M. Schwann, and A. Schnettler, “Asset management techniques,” Int. J. Electr. Power Energy Syst., vol. 28, no. 9, pp. 643–654, 2006. [18] IEEE Std. C57.12.90, 2006, IEEE Standard Test Code for LiquidImmersed Distribution, Power, and Regulating Transformers. [19] IEEE PC57.149, 2004, A Guide to Frequency Response Analysis in Oil-immersed Transformers. [20] IEEE Standard Requirements, Terminology, and Test Code for Shunt Reactors Rated Over 500 kVA, IEEE Std. C57.21, 2007. [21] IEEE C57.12.00, 2006, IEEE Standard General Requirements for Liquid-Immersed Distribution, Power and Regulating Transformers. [22] IEEE C57.113, 1991, IEEE Guide for Partial Discharge Measurement in Liquid-Filled Power Transformers and Shunt Reactors. [23] X. Zhang and E. Gockenbach, “Component Reliability Modeling of Distribution Systems Based on the Evaluation of Failure Statistics,” IEEE Trans. Dielectr. Electr. Insul., vol. 14, no. 5, pp. 1183–1191, 2007.

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Xiang Zhang received the B.Sc., M.Sc., and Ph.D. degrees in Electrical Engineering from Xi’an Jiaotong University, Xi’an, China, in 1989, 1992, and from the Aachen University of Technology, Aachen, Germany, in 2002, respectively. From 1992 to 1997, she was a research engineer at Xi’an High Voltage Apparatus Research Institute, Xi’an, China. Currently she is a research fellow on asset management of networks of the Schering-Institute of High Voltage Technology at the University of Hanover, Hanover, Germany. Her main areas of interest include high voltage apparatus, gas discharge, arc modeling, and asset management of networks. Ernst Gockenbach received the M.Sc. and Ph.D. degrees in Electrical Engineering from the Technical University of Darmstadt, Germany, in 1974, and 1979, respectively. From 1979 to

1982, he worked at Siemens AG, Berlin, Germany. From 1982 to 1990, he worked with E. Haefely AG, Basel, Switzerland. Since 1990, he has been professor and director of the Schering-Institute of High Voltage Technology at the University of Hanover, Hanover, Germany. He is member of VDE and CIGRE, chairman of CIGRE Study Committee D1 Materials and Emerging Technologies for Electrotechnology, and a member of national and international Working Groups (IEC, IEEE) for Standardization of High Voltage Test and Measuring Procedures.

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