In this paper, a methodology is developed to use data acquisition derived from condition monitoring and standard diagnosis for rehabilitation purposes... Asset management - Transformers - Condition monitoring - Aging - Failure analysis - Maintenance - Pollution measurement - Thermal stresses - Circuit testing - Power generation economics - condition monitoring - fault diagnosis - maintenance engineering - power transformer testing - transformer asset-management - condition monitoring - data acquisition - international test standards
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
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-
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 . 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
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 . 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 . 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 . 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) .
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.
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.
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
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 .
IEEE Electrical Insulation Magazine
Figure 6. Roger Ratio Criteria for DGA .
concentrations (TDCG) and their generation rates . 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 . 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
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
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.
July/August 2008 — Vol. 24, No.4
Table 5. Oxygen Test of Oil Limit
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
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
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
1. Minimum oil breakdown voltage < 20kV (for rated voltage < 288kV) 2. Minimum oil breakdown voltage <25kV (for rated voltage ≥ 287.5kV)
It indicates the amount of contaminants (water and oxidation) in oil.
This test is not extremely valuable since moisture will destroy cellulose insulation long before the dielectric strength of oil has indicated.
1. Oil should be reclaimed. 2. DGA test needs to be done.
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Figure 7: The relationships between water concentration, temperature, and moisture .
Figure 8: The relationships between IFT, acid number, and service year .
Doernenberg Ratio. Interpretation of fault conditions associated with gas concentration and combinations of these gases are also provided in .
significance are recommended for classification purposes and to determine the suitability for use of reclaimed oils.
B. Physical and Chemical Tests of Oil Quality
Furan analysis, degree of polymerization and CO2/CO ratio tests  may indicate a problem with the insulating paper (Tables 9–11), if the transformer is overheated, overloaded, aged, or after processing the oil (Table 9). The presence of these compounds is related to the strength of the paper as measured by its degree of polymerization (DP). DP is the average number of glucose molecules making the cellulose chains. The DP value decreases with time as the cellulose molecules break and fragment. The paper is assumed to age at a more rapid rate where the temperature of the paper and exposure to oxygen are the highest. Figure 9 depicts the relation between relative depolymerization velocity and the water content and temperature. When the DP test reveals a value of 200 or less, the paper is considered to have lost almost all mechanical strength, and the transformer has reached its end of life. The distribution of measured DP values in Figure 10 demonstrates that the technical lifetime of generator transformers is limited to 25 years whereas transmission transformers can reach a technical lifetime up to 50 years . As paper degrades, a number of specific furanic compounds are produced and dissolved in the oil. Furanic compounds are a
An important part of the life extension of a transformer is the restoration of the insulating fluid quality in the transformer. Physical and chemical tests such as moisture test, interfacial tension test, oxygen test, acidity test, power factor test, and dielectric strength test , ,  usually indicate oil conditions and operational characteristics (Tables 3–8). Moisture in a transformer decreases the dielectric strength of its insulation system (Figure 7). The combination of moisture, heat, and oxygen is the key factor that affects the rate of cellulose degradation. The interfacial tension (IFT) between insulating fluids and water is a measure of the molecular attractive force between unlike molecules at the interface. This test provides a means of detecting contaminants and products of deterioration (Figure 8). The oil conditions can be remedied through various reclamation processes. Therefore, they are not indicative of overall transformer condition, which would lead to replacement. Additional tests such as color, visual appearance, flash point, pour point, specific gravity, and viscosity , ,  to detect the presence of deleterious products of oxidation or contamination in service-aged oils also seem appropriate. These tests and their
C. Insulation Tests of Cellulose Paper
Table 9. Furans Test of Cellulose Paper Limit
Furans > 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.
July/August 2008 — Vol. 24, No.4
Table 10. DP Test of Cellulose Paper Limit
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
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<5. 5. The large increase in CO2 could mean an atmospheric leak when the ratio is above 10.
1. Extreme overheating from loss of cooling or plugged oil passages will produce a low CO2/CO ratio along with increasing Furans. 2. If H2, CH4, and C2H6 are increasing significantly as well as CO and CO2/ CO<5, there is probably a problem. 3. These problems are probably all reparable in the field where a fault will not degrade cellulose insulation.
1. If there is a sudden increase in H2 with CO2 and CO, this test is required. 2. De-energization and internal inspection is recommended. 3. DGA and Furans tests are taken immediately to confirm the problem.
family of molecules based on a furan ring structure. The most stable of these compounds is 2-furfuraldehyde, or 2-FAL. Thermal degradation of insulating paper could be monitored by furan analysis, especially when due to overheating conditions. Attempts have been made to relate the furanic content (2-FAL) of oil to the degree of polymerization (DP) of paper (Figure 11).
as blockages of cooling system, locating electrical connection problems and hot spots (Figure 12).
D. Infrared Thermograph Test The monitoring of temperature is usually not a problem and is very important to evaluate and to assess the influence of many other parameters, e.g. the humidity content in the oil or paper. An increase in temperature can indicate cooling problems or higher losses in the winding, core, bushing, arrester, tank, LTC, radiator, cooling system, and oil pump (Table 12). An increase of about 6 K to 8 K correlates with a doubling of the aging processes. An increase of about 75 °C will cause immediate failure of transformers . Thermography is a non-contact means of identifying thermal anomalies related to electrical and mechanical components that are exhibiting an excessive heat loss. The self-emitted radiation in the infrared portion of the electromagnetic spectrum is measured at the target surface and converted to electrical signals. It is useful for detecting thermal problems in a transformer, such
Figure 9: Relative depolymerization velocity at different water content and temperature .
IEEE Electrical Insulation Magazine
Figure 10. Aging behavior of cellulose insulation of transmission and generator transformers (GSU) .
E. Power Factor Test Power factor testing is important to determine the insulation condition of transformers because it can detect the insulation integrity in winding, bushing, arrester, tank, and oil (Table 13). The condition of bushings can also be determined by measurement of capacitance. Increased power factor may be the result of moisture or polar and ionic compounds in the oil . The aging of bushings is caused by cracking of the resin-bonded paper and inhomogeneous impregnation with insulating oil. The technical life time has a great scatter and should not exceed more than 30 years (Figure 13).
F. Capacitance Test As the transformer ages and events such as nearby lightning strikes or through faults occur, changes in the measured capacitances indicate winding deformation and structural problems such
as displaced wedging and support in winding and core (Table 14). The insulation condition of bushings can also be determined by measurement of capacitance . About 90% of bushing failures may be attributed to moisture ingress.
G. Excitation Current Test The purpose of this test is to detect short-circuited turns, poor electrical connections, core delaminations, core lamination shorts, LTC problems, and other possible core and winding problems (Table 15). The excitation current test ,  measures the single-phase voltage, current, and phase angle between them, typically on the high-voltage side with the terminals of the other winding left floating (with the exception of a grounded neutral). On three-phase transformers, results are also compared between phases. The measured current magnetizes the core and generates the magnetic fields in the windings.
Figure 11. Furan versus DP for thermally upgraded and non-thermally upgraded paper .
July/August 2008 — Vol. 24, No.4
Table 12. Infrared thermograph test Limit
1. Hotspot: unusual thermal patterns 2. Above ambient temperature >75 °C
1. Circulating stray currents. 2. Blocked cooling. 3. Bad tap changer contact. 4. High temperature may mean problems with winding, core, or connections. 5. Oil leakage. 6. Ingress of moisture and air. 7. Loose shields. 5. Catastrophic failure is imminent which can destroy nearby equipment and be hazardous to workers.
1. Abnormally high temperature can damage or destroy insulation systems and thus reduce life expectancy. 2. An increasing temperature of only 8 to 10 °C will reduce transformer life by one-half. 3. Test values are compared to previous or factory tests.
1. Immediate de-energization and replacement must be undertaken. 2. Internal inspection need to be investigated. 3. Doble test may show the problem.
H. Frequency Response Analysis (FRA) FRA  is used to help identify possible deformations and movements in the transformer core and coil assembly as well as other internal faults (Table 16). This test is also helpful if a protective relay has tripped or a through fault, short-circuit, or ground fault has occurred. The basis of the FRA technique is that the impedance of the transformer is related to the construction and geometry of the windings. Deformations and movements have an effect on both inductance and capacitance that may be reflected in the resulting frequency response. Therefore, a change in mechanical structure results in a change of the resonance frequencies. A change in electrical performance due to partial discharges also results in a larger damping of the resonance frequencies. Different aging mechanisms can be detected and identified at their respective frequency ranges. Shorted turns, open circuits, or core grounds determine the dielectric loss in the low-frequency range; core movement or damage is the dominant contributor in the medium-frequency range; and winding displacement or damage is the mechanical defect in the high-frequency range.
previous tests, and similar units to detect deformation of the core or windings due to shipping damage, through faults, or ground faults (Table 19).
L. Core-to-Ground Test The core-to-ground resistance test  can detect the default if this connection is loose or indicate if a spurious, unintentional core ground is the problem (Table 20). It can also supplement DGA test that shows the generation of hot metal gases. To check for unintentional core grounds, the intentional ground between the core and the grounded tank must be removed. If the intentional core ground is intact, the resultant resistance should be very low. Experience can help locate the source of the problem.
M. Winding Resistance Careful measurement of winding resistance can detect broken conductor strands, loose connections, and bad contacts in LTC  (Table 21). Results from these measurements may indicate
I. Vibration Test Vibration can result from loose core and coil segments, shield problems, loose parts, or bad bearings on oil cooling pumps or fans  of transformers (Table 17). If wedging has been displaced due to paper deterioration or through faults, vibration will increase markedly. It may also show if an internal inspection is necessary for transformers. Information gained from the vibration test supplements ultrasonic or acoustic detection and DGA tests.
J. Turns Ratio Test The turns ratio (TTR) test detects shorts or open circuits between turns of the same coil, which indicates insulation failure between the turns  (Table 18). All tap positions and all phases should be measured and may show the necessity for a further internal inspection or removal from service.
K. Leakage Reactance Test This test, sometimes called percent impedance test , is performed in the field and compared to nameplate information,
Figure 12. IR image of defective bushing .
IEEE Electrical Insulation Magazine
Table 13. Power factor test Limit
Power factor > 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 , . 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 : • 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 .
July/August 2008 — Vol. 24, No.4
Table 14. Capacitance Test Limit
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
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
Shape change >3dB
1. There is winding displacement or damage if frequency >10000Hz. 2. There is core movement or damage if frequency <5000Hz. 3. There are shorted turns, open circuits, or core grounds after shipping or a through fault if frequency < 2000 Hz.
1. By the winding transfer function in trace form, this test shows that damage has occurred during shipping or during a through fault. 2. Test values are compared to previous or factory tests.
1. This test should be conducted before and after transformer has been moved or after experiencing a through fault. 2. This test can show the exact phase position of problem. 3. Internal inspection should be considered before re-energized. 4. If the problem is severe, the unit may have to be taken out of service.
Table 17. Vibration test Limit
The measured frequency is twice the line frequency.
1. There is a good condition if the measured value is twice the line frequency. 2. Otherwise, loose parts, loose core, loose winding, bad bearings on oil pumps can be detected. 3. If wedging has been displaced due to paper deterioration or through faults, vibration will increase markedly.
Test values are compared to previous or factory tests.
1. Extreme care must be exercised in evaluating the source of vibration. 2. Internal inspection should be considered.
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Table 18. Turns ratio test Limit
Change in turns ratio to the nameplate value > 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
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
Resistance >1000 MΩ
A new transformer.
A trend can be established as insulation system ages.
Resistance > 100 MΩ
A service-aged transformer.
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
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.
July/August 2008 — Vol. 24, No.4
Figure 14. Fault location in a transformer winding .
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
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.
Therefore, the failure probability of transformers (P(t)) can be well described by the diagnostic model  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.
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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.
5TILIZING ADVANCED TECHNIQUES IN WINDING POLYGLASS INSULATING YARNS #ONNEAUT )NDUSTRIES IS NOW CUSTOM WINDING LARGER PRECISION SPOOLS FOR MAGNET WIRE MANUFACTURERS 4HESE #ONNEAUT SPOOLS PROCESS MORE YARDAGE AND CAPACITY THAN PREVIOUSLY POSSIBLE ! PROPRIETARY METHOD OF YARN LAYING ENSURES EVEN CONSISTENT AND UNIFORM PACKAGES !N INNOVATIVE PLASTIC SPOOL IS AVAILABLE IN METERED LENGTHS UP TO ENDS 4HE RECOGNIZED INDUSTRY LEADER OF INSULATING YARNS AND FIBERS #ONNEAUT PRODUCES SPECIALTY YARNS FOR A BROAD RANGE OF INDUSTRIAL APPLICATIONS BRAIDER PACKAGES SERVING SPOOLS AND HIGH CAPACITY PAYOFF REELS OF FIBERGLASS ROVINGREINFORCEMENTS FOR IGNITION WIRES