Condition Monitoring and Diagnostics of Bushings, Current Transformers, and Voltage Transformers by

Oil Analysis

1012343

ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 • PO Box 10412, Palo Alto, California 94303-0813 • USA

800.313.3774 • 650.855.2121 • askepri@epri.com • www.epri.com

Condition Monitoring and Diagnostics of Bushings, Current Transformers, and Voltage Transformers by Oil Analysis

1012343

Technical Update, December 2006

EPRI Project Manager

L. van der Zel

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES

THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION (S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION (S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:

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ORGANIZATION (S) THAT PREPARED THIS DOCUMENT

Powertech Labs Inc.

ORDERING INFORMATION

Requests for copies of this report should be directed to EPRI Orders and Conferences, 1355 Willow Way, Suite 278, Concord, CA 94520. Toll-free number: 800.313.3774, press 2, or internally x5379; voice: 925.609.9169; fax: 925.609.1310.

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Copyright © 2006 Electric Power Research Institute, Inc. All rights reserved.

Copyright © 2006 Electric Power Research Institute, Inc. All rights reserved.

iv

CITATIONS

This report was prepared by

Powertech Labs Inc. 12388-88th Ave. Surrey, BC, Canada V3W 7R7

Principal Investigator: Nick Dominelli Salim Hassanali

This document describes research sponsored by the Electric Power Research Institute (EPRI).

The report is a corporate document that should be cited in the literature in the following manner:

Condition Monitoring and Diagnostics of Bushings, Current Transformers and Voltage Transformers by Oil Analysis, EPRI, and Palo Alto, CA, 2006. 1012343

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ABSTRACT

This study was undertaken to determine the merits of oil analysis for condition monitoring and diagnostics of bushings, current, potential and voltage transformers. Oil test results and equipment information from 193 bushings, 830 current transformers, 194 potential transformers and 268 voltage transformers were analyzed. Statistical analyses was used to assigns equipment condition codes from 1 (Normal Operation) to 4 (Extreme) based on threshold limits for dissolved gas in oil results. A more recent set of about 800 test results was used to review potential faults in units previously flagged by high-level condition codes. These early results are assisting in the important task of understanding how to interpret DGA results from oil filled bushings, CTs, PTs, and VTs. For a participating member, the existing data forms a valuable early benchmark against which to compare their own results. Typical maintenance programs for bushings, current transformers (CT), potential transformers (PT) and voltage transformers (VT) consist of periodic external and off line electrical tests. Occasionally, more detailed oil testing has been done when a generic or design problem was suspected for specific CT and Bushing units. This time-based practice can be time consuming and expensive. Moreover, it may not be effective at detecting certain incipient faults. Dissolved gas in oil analysis (DGA) has the potential to detect conditions associated with incipient faults responsible for most failures. A research program was initiated to determine the merits of oil analysis as a diagnostic and condition assessment technique for oil filled bushings, CTs, PTs, and VTs.

Although the process worked well for identifying equipment at risk, we believe that combining laboratory test results with electrical field-test results and maintenance history could further improve the diagnostics process. Recommendations are made to proceed with additional work to develop a diagnostic algorithm combining the above data to refine the condition codes and set maintenance priority.

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ACKNOWLEDGEMENTS

The investigators are grateful to Toly Messinger for the opportunity to work on this project. We would also like to thank David Pugh and Mike Lau for all of their helpful suggestions.

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CONTENTS

1 OVERVIEW AND BACKGROUND ........................................................................................... 1

2 PROJECT SCOPE .................................................................................................................... 3

3 DATABASE AND WEB PAGE DESIGN................................................................................... 4 Database.................................................................................................................................. 4 Web Page Design .................................................................................................................... 4

4 OIL TESTS AND THEIR SIGNIFICANCE................................................................................. 5 Dissolved Gas in Oil (DGA)................................................................................................. 5 Application To Fault-Type Diagnostics In Power Transformers .......................................... 5 Application Of Fault Type Diagnostics to Bushings, CTs, VTs And PTs............................. 7

Detection and Identification of Electrical Discharges ............................................................. 10 Detection and Identification Of Thermal Faults ...................................................................... 12 Moisture ................................................................................................................................. 13 Extraneous Sources Of Gas .................................................................................................. 14 Other Tests .............................................................................. Error! Bookmark not defined.

5 RESULTS................................................................................................................................ 15 Condition Codes .................................................................................................................... 22

6 DISCUSSION AND CONCLUSIONS ...................................................................................... 31

8 APPENDICES ......................................................................................................................... 33

7 REFERENCES ........................................................................................................................ 37

1

1 OVERVIEW AND BACKGROUND

Typical maintenance programs for bushings, current transformers (CT) and voltage transformers (VT) consist of periodic external inspections and off line electrical tests. Occasionally, more detailed oil testing has been done when a generic or design problem was suspected for specific equipment. This time-based practice can be time consuming and expensive. Moreover, it may not be effective at detecting certain incipient faults. Records at BC Hydro have shown that some bushings that failed were not detected by routine electrical tests. In these cases, dissolved gas analysis (DGA) had indicated increases in the levels of acetylene. Recently BC Hydro has experienced several bushing failures. A 500kV bushing failure at a generating station resulted in a catastrophic failure of a generator transformer. Figure 1-1 shows the destructive nature of a bushing failure. Further testing of similar bushings has shown a failure rate of about 35%. Based on these results, BC Hydro has initiated an oil sampling and testing program for all 500 and 230kV bushings in their system [1]. Most utilities in North America have oil bushings that are of similar age (20-30 years old) and condition as those in the BC Hydro’s system and are expected to experience similar problems. Conditions that may lead to failure of bushings, CTs and VTs include the following: High moisture in the oil or paper. This may be the result of moisture ingress from leaky gaskets or

porous porcelain. Localized partial discharge due to insulation imperfections or design flaws Arcing due to internal flashover. Overheating and paper decomposition. This applies mainly to bushings on transformers that are

operated at high loads. Other problems relating to poor oil quality

Oil analysis has the potential to detect the above conditions associated with incipient faults responsible for most failures. The interpretation of test results for these types of equipment, however, is still in its infancy and requires further development. Although IEC has published some guidelines for threshold limits, they may not be suitable for all electrical utilities, such as BC Hydro, and may need to be tailored to specific substation equipment populations. There is a need to develop a methodology to determine threshold limits for DGA results and to develop diagnostics and condition codes that can be tailored to the profiles of individual companies, and then to individual substations.

Like many utilities, BC Hydro and BCTC already have an extensive database of DGA results for bushings, CTs, PTs, and VTs. Statistical analysis of these databases can be used to establish threshold limits. To further enhance these limits and develop diagnostic codes, BC Hydro and BCTC intend to start a more intensive program of oil sampling and analysis for in-service bushings, CTs and VTs.

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Equipment operating conditions and other relevant information will also be gathered and compiled into a database. The results of analysis will be correlated with the equipment condition, and assessed to determine its merits for diagnostics and condition assessment In summary the proposed future work program consists of collecting oil samples, nameplate information, operational data from in-service bushings, CTs and VTs, findings from inspections/teardowns (if available), and followed by comprehensive laboratory oil analysis. The results of analysis collected into a relational database and analyzed for trends and diagnostic merit.

Figure 1-1 500kV Bushing at a BC Hydro Generating Station [1]

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2 PROJECT SCOPE

The scope of this study was to:

Determine the merits of gas in oil analysis (DGA) for diagnostics and condition assessment of oil filled current transformers, voltage transformers, potential transformers and bushings.

Develop diagnostics limits to assign equipment condition codes based on gas in oil analysis.

Set up a secure web site to allow exchange of information and results.

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3 DATABASE AND WEB PAGE DESIGN

Database

Powertech Labs stores all the insulating oil test results from oil filled equipment for BC Hydro, BCTC, and third-party substations in a database called LabsysV2. All the oil results for CTs, VTs, PTs and Bushing units were extracted from this database using Access queries for further analysis, graphing etc.

Web Page Design A Web Page was created to exchange information and post final results with condition codes with diagnostics. Contact the EPRI Project Manager for the web site and password. The following information has been posted on this web page:

Project Description

Excel spreadsheets of CTs, VTs, PTs and Bushing units with condition codes and diagnostics.

Graphs of condition codes for CTs, VTs, PTs and Bushings units.

Diagnosis limits of the units

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4 OIL TESTS AND THEIR SIGNIFICANCE

Oil tests can reveal vital information about the condition of CTs, VTs, PTs and bushing units. The most critical step in obtaining meaningful and reliable results is to follow a proper sampling procedure. One of the most important oil tests for these units is Dissolved Gas in Oil Analysis. The levels and proportions of the contained gases are interpreted to identify a range of incipient fault types, which may occur in high-voltage equipment.

Dissolved Gas in Oil (DGA)

Gas in Oil Analyses is conducted on syringe samples sent to the Powertech test laboratories, and are performed according to ASTM D3612. The concentrations of the following gases are measured in parts per million by volume (ppm v/v): Hydrogen, Oxygen, Nitrogen, Carbon Dioxide, Carbon Monoxide, Methane, Ethylene, Ethane, Acetylene and Propane. The water content is also measured using the same syringe sample but these results are reported in parts per million by weight (ppm w/w).

Insulating oils under abnormal electrical stresses break down to liberate small quantities of gas. The qualitative composition of the breakdown gases is dependent upon the type of the fault. By means of dissolved gas analysis (DGA) of the oil, it is possible to distinguish faults such as partial discharge (corona), overheating (Pyrolysis), and arcing in a variety of oil filled equipment. A number of samples must be taken over a period of time for developing trends and to determine the severity and progression of incipient faults.

Application To Fault-Type Diagnostics In Power Transformers

The application of DGA as a tool for fault detection and condition assessment of oil-filled power transformers is well established and there is very extensive documented research on the subject. DGA is increasingly used for LTCs and circuit breakers as well - but the range and sensitivity of the method is less clearly defined. DGA interpretation techniques are currently based on the same chemical and physical principles as the Rogers Ratios and Duval Triangle. Both of these methods are consistent with Halstead’s thermodynamic reasoning that the hydrocarbon gas with the maximum rate of evolution as the oil temperature increases is (in turn): methane, ethane, ethylene, and acetylene. Of course, there are other gases usually present in an oil sample, notably hydrogen, carbon monoxide, carbon dioxide, moisture, C3 hydrocarbons, and air. The levels and proportions of all of these gases are usually taken into consideration when data is available. Electrical and thermal faults break the C-H and C-C bonds in the oil molecules resulting in a range of small unstable ions and radicals. The H , CH3 , CH2 , CH , and C fragments recombine into gas molecules such as hydrogen (H-H), methane (CH3-H), ethane (CH3-CH3), ethylene (CH2=CH2), or

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acetylene (C2H2). Other possible recombination products are C3 and C4 hydrocarbon gases, solid particles of carbon and hydrocarbon polymers (X-wax). Cellulose-based insulation (paper, pressboard, wood, etc) consists of polymeric molecules with comparatively weak C-O and glycosidic chemical bonds. The polymeric bonds start to break at temperatures above 105oC. Complete destruction (carbonization) occurs above 300oC. As a result, the oil-impregnated insulation releases CO, CO2 and H2O at a very low rate at normal transformer operating temperatures. A higher rate of evolution indicates overheating. It is often difficult to distinguish between CO and CO2 evolution from moderately overheated bulk insulation and similar amounts of gas from confined areas such as winding hot spots. The theoretical considerations, laboratory tests, and practical experience have established a simple relationship between “key” gases and the different fault conditions, as follows: H2 – Corona discharges* CH4 and C2H6 – Low temperature oil decomposition C2H4 – High temperature oil decomposition C2H2 – Arcing** CO and CO2 - Cellulose insulation decomposition*** *Hydrogen can be produced from many sources. It is produced along with hydrocarbon gases in thermal processes. It is the primary gas evolved from corona discharges, electrolysis of water, and rusting.

** High C2H2 indicates temperatures in excess of 1000C, which are only attained in arcs and sparks. Arcing also produces carbon particles. *** A CO2/CO ratio of 8 or higher is considered normal for thermal decomposition. A low CO2/CO ratio (< 3) may indicate electric discharges. Small quantities of CO and CO2 may also be produced by oil oxidation. Air-saturated oil contains about 500ppm CO2. Powertech has developed a new DGA diagnostic tool, known as “Vector”. Vector’s approach is to view the dissolved gas concentrations as the result of a combination of “activities” identified as:

Arcing (ARC), Partial discharge (PDO), Pyrolysis metal/oil (PMO), Overheated oil (OHO), and Overheated cellulose (OHC).

The DGA results usually indicate a preponderance of one of these activities, but Vector is not restricted to analyzing a single type of fault activity. The five activities can occur at different intensities in different parts of the apparatus, in different time frames, or even concurrently in the same component. For example, a partial discharge activity is likely to precede an arcing breakdown. When single or combined activity levels rise above a certain limit, the condition can be classified as a fault. Making this distinction allows Vector to be more universal in its application. A minor arcing

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activity in a transformer or reactor is usually considered a fault, but the same activity in an on-load tap changer or circuit breaker is considered normal operation Vector calculates the amount of gas attributable to each of the five activities. The outputs are scaled by coefficients a, b, c, d, and e, which have been derived from the gas level tables for transformers in IEEE C57.104. These coefficients can be adjusted to allow for various factors, such as the type and age of the equipment. Each of the condition levels, such as PDO = a (PDOppm), can be viewed independently or as a sum, Cv, indicating the overall condition of the insulation.

Cv = a (PDOppm) + b (ARCppm) + c (OHCppm) + d (OHOppm) + e (PMOppm)

Vector provides numeric data, which is readily tabulated and charted. Charts are particularly helpful in identifying changes in fault patterns as they develop over time. Vector is very helpful for monitoring units with suspected faults; to rank the reliability of units within a substation, perform statistical analyses on a gradually aging population of transformers, etc.

Application Of Fault Type Diagnostics to Bushings, CTs, VTs And PTs DGA diagnostic procedures are well established for power transformers. The development of similar diagnostic criteria to other types of oil-filled substation apparatus is of considerable interest. Considerable progress has been made in developing new diagnostic rules to Load Tap Changers (LTCs) and Circuit Breakers. This has required considerable research into the mechanisms of gas production along with detailed studies of DGA data from laboratory simulations and well-documented examples of equipment failures. The application of “power transformer” diagnostics to other non-reactive types of equipment will be most successful when there is a high degree of similarity in the function and configuration of the oil-impregnated insulation. The equipment types considered in the current project fall into two groups: Voltage Transformers/Potential Transformers, in which the insulation is fairly similar to power transformers, and Current Transformers/Bushings where the insulation is more like oil-filled cables than power transformers.

Station-Service Voltage Transformers and Potential Transformers Station service voltage transformers (SSVTs) are autotransformers, which are used to provide low voltage control power for substations by tapping directly from the high voltage transmission line. Most voltage transformers can be calibrated to provide power and meter/relaying simultaneously. Station service potential transformers (PTs) in which the primary winding is connected in shunt with the voltage that is to be measured. The secondary winding provides an accurate low-voltage output which is used for meter/relaying and indication purposes. Both types of equipment use cellulose paper and oil insulation in much the same way as power transformers and also have high oil/paper volume ratios.

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It would seem reasonable to use a different set of DGA limit tables for SSVTs and PTs and to use similar fault identification procedures (Duval Triangle etc.) to those for power transformers. Over the years, a number of voltage transformers and potential transformers have been tested for dissolved gases, and the results have been successfully interpreted using “power transformer” diagnostics. Current Transformers and Bushings Current transformers (CTs) are instrument transformers, in which the primary winding is connected in series with the conductor carrying the current to be measured. The secondary winding provides an accurate low-current output, which is used for relaying, metering, and indication purposes. Normally, a free standing CT is completely filled with oil to the top of the bushing. The bushing section contains a heavy current-carrying conductor that runs from one of the top connections down through the center of the unit and back up to the other terminal. This provides a single-loop primary circuit. The bottom housing contains the secondary (step-down) winding. There is full line voltage between the current loop, bushing flange, and secondary winding, requiring many layers of impregnated paper-oil insulation. High-voltage bushings (Bushings) carry current at line potential through a grounded barrier, such as a transformer tank, circuit breaker, or building wall. Condenser bushings facilitate electrical stress control through insertion of floating equalizer (electrode) plates. They decrease the field gradient and distribute the field along the length of the insulator, which provides for low partial discharge levels. The equalizer plates are made from metallic foils (aluminum or copper) or conducting ink patches which are located coaxially to achieve an optimum balance between external flashover and internal puncture strength. The core is built up around a hollow centre tube, and is wound from Kraft (and sometimes Nomex) paper for high temperature and current applications. The whole structure is impregnated with dry degassed oil, which is topped up from a reservoir on the upper end of the bushing. Figure 4-1 is a diagram of a typical bushing. Current transformers and bushings contain massive current-carrying conductors at line voltage, which are in close proximity to grounded metal components. Very thick layers of oil/paper insulation, with very few oil gaps, provide the electrical insulation. DGA results from a fairly large number of bushings and current transformers have been moderately successful in detecting abnormal conditions. However, there is concern that DGA is not as sensitive to developing faults as in power transformers, and that some gases (and moisture) will diffuse too slowly through the thick oil-impregnated cellulose insulation. The proportions of oil and paper are also quite different from power transformers. The amount of oil contained in oil-impregnated paper is about 7 % of the total volume of oil in a power transformer. The ratio of free oil to cellulose in high-voltage bushings and current transformers is much less than this, and gas generation in the cellulose is likely to predominate. A further concern is that gases and moisture diffuse very slowly through oil-impregnated cellulose. There is also much more restricted oil circulation, and the gases may take a long time to reach an oil sampling port.

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1. Gas cushion 2. Oil filling unit (hidden) 3. Quartz filling 4. Paper insulated primary conductor 5. Cores/Secondary windings 6. Secondary terminal box 7. Capacitative voltage tap 8. Expansion vessel 9. Oil sight glass 10. Primary terminal 11. Earth terminal

Figure 4-1 Current transformer: ABB Power Systems – Olaf Samuelsson These factors indicate that DGA results cannot be interpreted in the same way in bushings and current transformers as for power transformers. Standard diagnostic procedures may still apply to faults occurring in pockets of free oil, such as overheated contacts at the top of bushings, but different

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criteria will be required to interpret dissolved gases generated in the bulk insulation. Diagnostics will require new DGA limit tables, the “Duval Triangle”-“gas ratio” methods will not apply, and “key gases” will have to be used with care.

Detection and Identification of Electrical Discharges

DGA can distinguish two types of electrical discharges in transformer oil. They are Partial Discharges (sometimes referred to as Corona) and Arcing. Partial discharges produce mostly hydrogen (H2) in the oil, with very small amounts of other hydrocarbon gases and no acetylene (C2H2). Arcing, from the largest power breakdown to the tiniest discharges (e.g. in ASTM D1816 tests), produces C2H2 along with hydrogen and other hydrocarbons. As a result, the discovery of C2H2 in the oil is a strong indicator that arcing has taken place. The high temperatures attained in an arcing channel are sufficient to vaporise metals and produce carbon from the oil and any adjacent cellulose material. Tracking discharges along oil-impregnated paper will produce acetylene, carbon, and cellulose Pyrolysis products. The “Partial Discharges” (Corona) identified by DGA are plasma discharges, similar to the ones produced in ASTM Gassing Tendency tests. They take place in gas bubbles or voids where voltage stress is sufficient to initiate electron avalanches and more extensive oil ionisation. Prolonged corona activity in oil produces large amounts of hydrogen, X-wax, but practically no carbon. Typical gas composition for these two types of faults is shown in Figure 4-2.

Figure 4-2 Typical gas compositions resulting from arcing and partial discharges in oil

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Previous work found that about 1.5 ml of gas along with 0.4 mg carbon and 0.2 mg metal were produced per switch operation in an LTC. [2] Research at IREQ established that 90 ml of gases were produced per kJ of arc energy in reclosers. [3] A recent CIGRE paper states “PD energies of 100 mJ, corresponding for example to several discharges of 100,000 pC to 1 million pC, are necessary to generate 5 to 7 l of gas.” [4], [5], [6]. This data indicates that the two types of dielectric breakdown produce similar amounts of gas, 90 l/Joule (arcing) and 50 l/Joule (partial discharges). If the proportions of the “key” gases are taken into account (Figure 4-2) it is found that partial discharges produce about 40 l of H2 and arcing produces 38 l of C2H2 per Joule of energy; almost identical amounts. The CIGRE paper also points out that 50 l of gas in a transformer containing 50,000 L of oil will result in a concentration of only 1 ppm, implying that DGA is incapable of detecting sporadic PDs in the low-to-medium pC range. Bushings, CTs, VT’s and SSVTs contain smaller amounts of oil, and the sensitivity of DGA is likely to be much higher. Figure 4-3 is a picture of a typical bushing. As a result, DGA combined with high sensitivity electric or acoustic PD tests offer the best chance of detecting electrical discharges before they cause major damage.

Figure 4-3 Bushing Tap Coupler (AVO New Zealand)

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Detection and Identification Of Thermal Faults

DGA can identify thermal faults in oil from those in oil-impregnated paper based on the levels of hydrocarbon gases compared to carbon monoxide/dioxide. Significant production of hydrocarbon gases requires very high temperatures (>400oC). The production of carbon monoxide/dioxide from paper requires only moderately elevated temperatures (>150oC). The high temperatures required to thermally decompose oil result primarily from direct contact with a hot metal surface. In power transformers, these conditions are typically produced at overheated joints between conductors, excessive circulating currents, and parasitic core overheating. Elevated ethylene levels and only trace amounts of acetylene are strong indicators of thermally decomposing oil. This may occur at overheated joints at the top of bushings. Carbon monoxide/dioxide gases are evolved from long-term moderate (normal) heating in the bulk of the oil-impregnated cellulose, and by hot spots, which develop under increased load. Although the rate of production of carbon monoxide/dioxide increases very rapidly with temperature, the proportion of carbon monoxide to carbon dioxide remains about the same. DGA is consequently unhelpful in distinguishing hot spots from bulk overheating on the basis of carbon monoxide/dioxide levels. Moderately heated oil-impregnated cellulose will also produce minor amounts of hydrogen, methane, ethane, and ethylene but no acetylene. Figure 4-5 gives typical rates of gas formation from overheated paper. The hydrocarbon gases probably come from the oil, but the prevalence of fairly high levels of hydrogen in bushings and cables indicates that cellulose may be a major source.

a B. Noirhomme, Hydro Quebec b M. Martins, Labelec c H. Foschum, Va Tech Figure 4-4 Gases evolved from Overheated Cellulose

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Moisture

High levels of moisture significantly reduce the dielectric strength of oil and oil-impregnated paper. Although rigorous action is taken to exclude moisture from high-voltage equipment, the insulation always contains some level of absorbed water. Apparatus may accumulate amounts of free water if rain gets in or there is long-term access to air. Cellulose can absorb large quantities of water, in marked contrast to the oil. The migration of moisture from the cellulose to the free oil in transformers is very temperature dependent, making assessments of insulation moisture content based on oil samples difficult and complicated. Although the oil can “wet up” very rapidly as the temperature rises, migration back into the paper is typically much slower. The slow rate of diffusion of moisture through oil-impregnated paper is also a factor to be considered when interpreting the results of moisture-in-oil tests. Figure 4-5 shows the diffusion time constants of water in paper at different temperatures. Note that the temperature effect diffusion rate is exponential.

Figure 4-5 Diffusion time constants – 1/4 inch Pressboard [7]

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Extraneous Sources Of Gas

These include:

1. Hydrogen from rusting 2. Hydrogen from the electrolysis of free water 3. Stray gassing in new oil 4. Photochemical reactions (action of sunlight)

Stray Gassing is the formation of gases from insulating mineral oils heated at relatively low temperatures (90-200 C). It has become more prevalent in recent years because of changes in refining techniques. Bushing oils are very carefully blended to minimise stray gassing – and it is unlikely to be a concern. Reference [8] provides values of stray gassing for different oils as a function of hottest spot temperature.

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5 RESULTS

All the results of the Gas in Oil for CTs, PTs, VTs and Bushings units were extracted from the Labsys database and transferred to individual MS Excel files. In order to avoid bias towards equipment with having multiple tests, statistical analysis was done on the most recent results only. All data was used for determining historical trends and diagnostics.

Data Analysis All the gas in oil results of these instrument equipments were examined carefully and exceptionally high results were left out of the file when doing statistically analysis. The reason for this was that exceptional high results would affect the statistically analysis significantly. Most of these high values were also from failed equipment. By eliminating very high gas values would also make the limits more reliable and more representative of normal operating equipment.

Data analysis was performed in two possible ways:

1) Standard Deviation Method: Standard deviations were calculated for each of the gases. (Appendix 1) Gas values above two standard deviations were to be considered at a higher risk. This method was not used in the final analysis because the databases for these units are currently not large enough. In this case, one or two outlier results could result in a large standard deviation and mislead the user.

2) Percentile Method: The percentile method was used to calculate the condition codes of these equipments. The percentile method was preferred because it would not alter the values of the gases with even high results. For this project the definition of a Percentile is a value on a scale of one hundred that indicates the percent of a distribution that is equal to or below it. For example we can see from Figure 5-1 that the 80 percentile for H2 in PTs is about 25ppm, this means that 80 % of all results are equal to or less than 25ppm.

The percentiles for each equipment type are shown in Figures 5-1 to 5-5 and the population distribution in Figures 5-6 to 5-11.

For the DGA results, percentile values above 90% were considered significant since these values were above or equal to the 90% of the values in the database. This is the value most commonly used in the industry and recommended by IEC 60599. This value was selected for practical reasons – to avoid spending too much resources on the lower 90% of the cases where faults are less likely to occur and focus on the upper 10% with higher probability of failure.

Percentile values from 90% to 99% were given increasing condition codes to reflect increasing severity of the unit condition. CIGRE TF 15/12-01-11 has determined pre-failure gas concentrations (PFGS) for transformers from databanks with failure related events. The probability of having a failure-related event in service (PFS) was defined as the ratio between the number of DGA cases followed by such an event, to the

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total number of analysis, at different gas concentrations. By plotting the PFS as a function of gas concentration level the PFGC concentration was determined. For transformers, this value was typically at the 98 to 99 percentile.

Although we don’t have enough failure data to calculate the PFGC for our equipment, we think that the same approach is valid and have assigned a condition code of “extreme’ at the 99 percentile.

Figure 5-1 Percentile of Fault Gases and Moisture for PTs

Plot of Gas values Vs Percentile for CTs

0

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0 100 200 300 400

G

C2H4C2H6CH4H2H20

Figure 5-2 Percentile of Fault Gases and Moisture for CTs

P lo t o f G a s v a lu e s V s P e r c e n t i le fo r P T s

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e C 2 H 4C 2 H 6C H 4H 2H 2 0

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Figure 5-3 Percentile of Fault gases and Moisture for PTs

Figure 5-4 Percentile of Fault Gases and Moisture for VTs

Plot of Gas values Vs Percentile for PTs

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0 20 40 60 80 100 120ppm Gas

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e C2H4C2H6CH4H2H20

Plot of Gas values Vs Percentile for VTs

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0 50 100 150 200 250ppm Gas

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e C2H4C2H6CH4H2H2O

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Figure 5-5 Percentile of Fault Gases and Moisture for Bushings

Plot of Percentile values of Bushings

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0 100 200 300 400 500ppm gas

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e C2H4C2H6CH4H2H20

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Figure 5-6 Population Curve for C2H2 in Bushings

Figure 5-7 Population Curve for C2H6 and CH4 in Bushings

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Figure 5-8 Population Curve for H2 in Bushings

Figure 5-9 Population Curve for CO2 in Bushings

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Figure 5-10 Population Curve for CO in Bushings

Figure 5-11 Population Curve for H2O in Bushings

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Condition Codes

The test results from DGA and moisture were used to assign condition codes for each equipment. The results were condensed to the following five main categories and their diagnostic significance, these are:

Acetylene gas Levels - Arcing

Moisture Levels – High Moisture

Total Carbon monoxide and dioxide gas– Cellulose Breakdown

Hydrogen gas Levels – Corona

High Hydrocarbon Levels - Thermal

All units were given a condition code based on the above to reflect its condition diagnosis. These are illustrated below.

Condition Code 0 (as new): The equipment is new and all gas levels are well below the limit. All results under 90% percentile were in this group.

Condition Code 1 (Normal): The equipment is operating normally and the gas levels are at normal levels. In this state the unit should be regularly checked. All results at 90% percentile were in this group.

Condition Code 2 (Cautionary): The equipment is in fair condition and should be checked more frequently. The results are slightly above normal. All results at 95% percentile were in this group.

Condition Code 3 (Warning): The equipment results are well above normal and the equipment should be checked again as soon as possible. All results at 99% percentile were in this group.

Condition Code 4: (Extreme): The results have exceeded above normal and are increasing rapidly. The equipment should be checked immediately.

The results of the condition code for each unit are listed in Appendix 1 and 2. A summary of condition codes along with their percent distribution for each equipment type is given in Table 5-1.

23

Table 5-1 Summary of Equipment Conditions

Current Transf. Potential Transf Voltage Transf. Bushings

Condition Units % Units % Units % Units % 0 – Near New 111 13 11 6 8 3 7 4 1- Normal 476 57 127 65 172 64 118 61 2- Cautionary 109 13 21 11 31 12 22 11 3 - Warning 102 12 14 7 46 17 25 13 4 - Extreme 32 4 21 11 11 4 21 11 Total 830 100 194 100 268 100 193 100 The individual DGA values of the databases were coloured coded based on the limits set by calculating the percentile values. A summary of the results is given in Table 5-2. The data bases of all results are posted on a Powertech Labs web page (contact EPRI Project Manager for site and password). The files posted on the web page are:

CT.xls – Results of the Current Transformers with condition code and diagnosis.

VT.xls - Results of the Voltage Transformers with condition code and diagnosis.

PT.xls - Results of the Potential Transformers with condition code and diagnosis.

Bushing units - Results of the Bushing units with condition code and diagnosis. Diagnosis Limits – Limits of the DGA results

24

Threshold Levels Threshold levels are usually taken as the 90 percentile values. However sometimes the 95 percentile are used. The IEC has published some threshold levels for CT, VT, and bushings. These are listed in the Appendix 3. Table 5-2 gives a comparison of the IEC threshold levels compared to Powertech’s values derived from the databases. We can see that in most cases, the PLI (Powertech Labs Inc,) database threshold levels are within the IEC range, although the range is very wide. One notable exception is the H2 levels for bushings. As we can see, the database levels are more than double those of the IEC. Also the levels of C2H2 for the database are consistently lower and generally less than 2ppm. Table 5-2 DGA Threshold Levels from IEC and PLI

Equip. Type Percentile H2 CO CO2 CH4 C2H6 C2H4 C2H2 CT- PLI 90% 65 576 1544 10 10 20 1

CT – IEC 0% 6-300 250-1100 800-4000 11-120 7-130 3-40 1-5

VT – PLI 90% 56 938 4400 27 10 17 0

VT-IEC 90% 70-1000 20-30 4-16

Bush - PLI 95% 370 937 4953 61 71 20 0

Bush- IEC 95% 140 1000 3400 40 70 30 2

IEC = IEC 60599 Publication; PLI = Powertech Labs Inc. Table 5-3 overleaf provides a summary of all the equipment percentiles, conditions and actions in the database.

25

Table 5-3 Summary of Equipment Percentiles, Conditions and Actions

The relative distribution of condition codes for each equipment type is shown in Figures 5-12 to 5-15. It is interesting to note that 65 to 70 % of all equipment types are normal or as new. Only 5% of VTs and CTs are in extreme condition but that increases to about 11% for PTs and bushings.

Percentile Values Conditions and Recommended Actions Current Transformer

Percentile C2H2 C2H4 C2H6 CH4 H2 H2OCode Condition Action <90% <1 <20 <10 <10 <65 <12 0 Near New Continue 90% 1 20 10 10 65 12 1 Normal Monitor Change 95% 2 29 16 14 99 19 2 Cautionary Increase Sampling 99% 5 49 32 28 363 38 3 Warning Resample >99% >5 >49 >32 >28 >362 >38 4 Extreme Immediate Sampling

Bushings Percentile C2H2 C2H4 C2H6 CH4 H2 H2OCode Condition Action <90% 0 17 56 42 278 17 0 Near New Continue 90% 0 17 56 42 278 17 1 Normal Monitor Change 95% 2 20 71 61 370 21 2 Cautionary Increase Sampling 99% 16 27 202 116 441 63 3 Warning Resample >99% >16 >27 >202 >116 >441 >63 4 Extreme Immediate Sampling

Potential Transformer Percentile C2H2 C2H4 C2H6 CH4 H2 H2OCode Condition Action <90% 0 14 9 24 35 19 0 Near New Continue 90% 0 14 9 24 35 19 1 Normal Monitor Change 95% 1 24 17 32 55 29 2 Cautionary Increase Sampling 99% 3 42 61 43 108 63 3 Warning Resample >99% >3 >42 >60 >43 >108 >62 4 Extreme Immediate Sampling

Voltage Transformer Percentile C2H2 C2H4 C2H6 CH4 H2 H2OCode Condition Action <90% 0 <17 <10 <27 <56 <22 0 Near New Continue 90% 0 17 10 27 56 22 1 Normal Monitor Change 95% 2 42 18 33 126 32 2 Cautionary Increase Sampling 99% 9 88 121 72 241 81 3 Warning Resample >99% >9 >88 >121 >72 >241 >81 4 Extreme Immediate Sampling

26

Figure 5-12 Distribution of Diagnostic Condition for CTs

Figure 5-13 Distribution of Diagnostic Condition for PTs

D is t r ib u t io n o f D ia g n o s t ic C o n d it io n fo r C T s

1 3 %

5 8 %

1 3 %

1 2 %4 %

0 - N e w1 - N o rm a l2 - C a u tio n a ry3 - W a rn in g4 - E x tre m e

D is t r ib u t io n o f D ia g n o s t ic s C o n d i t io n f o r P T s

6 %

6 5 %

1 1 %

7 %

1 1 %0 - N e w1 - N o r m a l2 - C a u t io n a r y3 - W a r n in g4 - E x t r e m e

27

Figure 5-14 Distribution of Diagnostic Condition for VTs

Figure 5-15 Distribution of Diagnostic Condition for Bushings

Distribution of Diagnostic Condition for VTs

3%

64%

12%

17%

4%0 - New1- Normal2- Cautionary3 - W arning4 - Extreme

D is tr ib u tio n o f D ia g n o s tic C o n d itio n fo r B u s h in g s

4 %

6 1 %

1 1 %

1 3 %

1 1 %0 - N e w1 - N o rm a l2 - C a u tio n a ry3 - W a rn in g4 - E xtre m e

28

Fault Type Diagnosis Color-coded tables are useful for identifying the Diagnostic Condition level of equipment. Figure 5-16 shows some color-coded results for high-voltage bushings along with Diagnoses based on key gases C2H2, C2H4, CO2, H2 and H2O.

Figure 5-16 Color Codes For Individual Gases Corresponding To Condition Levels

All the equipment results with condition code 3 and 4 were given a diagnosis based on the results. It is recommended that these units should be sampled again to confirm the high condition code. The equipment diagnosis with condition code 3 and 4 are summarized below in Figures 5-17 to 5-20.

Diagnosis of CT units with condition code 3 and 4 Arcing Cellulose Breakdown Corona High Moisture Condition 3 28 27 23 25 Condition 4 8 7 9 8 Total 36 34 32 33

29

Figure 5-17 Charts of Total CT Units and Equipment Diagnosis

Diagnosis of PT units with condition code 3 and 4 ArcingCellulose Breakdown CoronaHigh MoistureThermal FaultCondition 3 2 0 7 5 0 Condition 4 7 2 3 2 6 Total 9 2 10 7 6

Figure 5-18 Chart of Total PT units and Equipment Diagnosis

D is tr ib u tio n o f D ia g n o s is fo r C o n d itio n C o d e 3 a n d 4 fo r C u rre n t T ra n s fo rm e r U n its

05

1 01 52 02 53 03 54 0

A rc in g C e llu lo s eB re a k d o w n

C o ro n a H ig hM o is tu re

D ia g n o s is

Tota

l Uni

ts

C o n d itio n 4C o n d itio n 3

D is t r ib u t io n o f D ia g n o s is f o r C o n d i t io n C o d e 3 a n d 4 f o r P o t e n t ia l T r a n s f o r m e r U n i t s

0

2

4

6

8

1 0

1 2

A r c in g C e llu lo s eB r e a k d o w n

C o r o n a H ig hM o is tu r e

T h e r m a lF a u ltD ia g n o s is

Tota

l Uni

ts

C o n d it io n 4C o n d it io n 3

30

Diagnosis of VT units with condition code 3 and 4 Arcing Cellulose Breakdown Corona High Moisture Condition 3 5 2 13 13 Condition 4 6 15 3 0 Total 11 17 16 13

Figure 5-19 Chart of Total VT units and Equipment Diagnosis

Diagnosis of Bushing units with condition code 3 and 4 Arcing Cellulose Breakdown Corona High Moisture Condition 3 3 6 9 7 Condition 4 9 6 4 2 Total 12 12 13 9

Figure 5-20 Chart of Total Bushing units and Equipment Diagnosis

Distribution of Diagnosis for Condition Code 3 and 4 for Voltage Transformer Units

02468

1012141618

Arcing CelluloseBreakdown

Corona High Moisture

Diagnosis

Tota

l Uni

ts

Condition 4Condition 3

D is t r ib u t io n o f D ia g n o s is fo r C o n d i t io n C o d e 3 a n d 4 fo r B u s h in g U n i ts

02468

1 01 21 4

A rc in g C e llu lo s eB re a k d o w n

C o ro n a H ig hM o is tu re

D ia g n o s is

Tota

l Uni

ts

C o n d it io n 4C o n d it io n 3

31

6 DISCUSSION AND CONCLUSIONS

A total of 193 bushings, 830 current transformers, 194 potential transformers and 268 voltage transformers were analyzed in this study and populated in a database available to the project participants. These early results are assisting in the important task of understanding how to interpret DGA results from such devices. For a participating member, the existing data forms a valuable early benchmark against which to compare their results. The specific project goal in 2006 was to applying statistically appropriate techniques to identifying units in the database which were at a higher risk of failure. Percentile analysis was the technique selected – and was used to identify high-risk units (identified with condition codes of 3 and 4). Typical concentrations (90%-95%) of the gases in these equipments have been published by IEC 60599. (Appendix 3) The 90%-95% percentile results obtained from the data captured to-date in the databases were much lower than published by IEC. Some of the gases were twice as much lower than the IEC limits. Any acetylene gas present in the instrument transformers (CT,VT and PT) was considered to be at a higher risk of failure according to our diagnostics but the IEC values does tolerate low levels of acetylene. IEC recommends that threshold limits of the gases should be calculated using one’s own equipment databases. Furthermore – future data added to the database may shift these percentiles. Correlation of failure histories and electrical test data with the gas in oil results could further enhance the diagnostic procedure. Future research could examine the value added by this additional information. The results of such an extension to the research could be condensed into a guide for individual substations indicating acceptable gas level limits for CTs, VTs, and PTs and bushing units. These limits could also be used in corporate databases to assist in maintenance and unit replacement operations.

32

33

7 APPENDICES

APPENDIX: 1

STANDARD DEVIATION VALUES OF EQUIPMENT

Current Transformers C2H2 C2H4 C2H6 CH4 CO CO2 H2 H2O N2 O2 MAX 5085 5989 452 1469 1179 20893 5104 99 169725 48837 MIN 0 0 0 0 0 0 0 0 0.7516 0.293 AVERAGE 3.0 9 5 8 219 718 45 10 61577 10060 STDEV 114 134 14 40 222 684 208 12 23220 9209 2STDEV 228.1 269 29 79 444 1369 416 23 46440 18418 Potential Transformers C2H2 C2H4 C2H6 CH4 CO CO2 H2 H2O N2 O2 MAX 1597 35288 19042 34294 3178 12321 9815 187 757956 37193 MIN 0 0 0 0 0 10 0 0 1412 406 AVERAGE 14 211 77 133 401 2493 112 12 64778 17837 STDEV 120 1565 814 1463 372 2407 579 14 35155 10684 2STDEV 240 3130 1627 2927 745 4815 1158 28 70309 21368 Voltage Transformers C2H2 C2H4 C2H6 CH4 CO CO2 H2 H2O N2 O2 MAX 381 396 290 5220 2920 62271 5724 81 717508 46331 MIN 0 0 0 0 0 0 0 0 0 0 AVERAGE 3 11 10 28 499 2794 37 11 79269 16067 STDEV 27 28 30 239 378 4223 261 12 35053 10452 2STDEV 54 56 60 478 756 8445 522 24 70106 20904 Bushing Units C2H2 C2H4 C2H6 CH4 CO CO2 H2 H2O N2 O2 MAX 3005 2681 376 1579 1335 27972 11335 68 122514 38096 MIN 0 0 0 0 1 9 0 2 29579 50 AVERAGE 20 32 27 35 301 2331 185 8 70155 7223 STDEV 217 234 56 131 293 4138 900 10 15873 8973 2STDEV 434 467 111 262 587 8276 1800 19 31745 17946

34

APPENDIX: 2

PERCENTILE VALUES OF EQUIPMENT

Percentile Values of Current Transformers Percentile % C2H2 C2H4 C2H6CH4COCO2H2H2O N2 O2 Gas % TDCG

10 0 0 0 1 35 297 4 3 17326 455 2 85 20 0 1 0 2 64 470 6 3 46432 939 5 117 30 0 1 1 3 123 619 8 4 59733 3612 7 164 40 0 1 1 4 192 751 10 4 65165 7328 8 226 50 0 3 1 5 241 845 13 5 7022210620 8 272 60 0 4 2 6 297 941 17 6 7386614405 9 336 70 0 5 3 7 381 1055 21 7 7648517282 9 412 80 0 8 6 8 461 1257 36 8 7940020320 10 507 90 1 20 10 10 576 1544 65 12 8351223934 10 666

90 IEC low 1 3 7 11 250 800 6 - - - - - 90 IEC high 5 40 130 120 1100 4000 300 - - - - -

95 2 29 16 14 699 1776 99 19 8631527844 11 834 99 5 49 32 27 962 2385 362 38 9188332821 11 1134

Percentile Values of Potential Transformers Percentile % C2H2 C2H4 C2H6CH4COCO2H2H2O N2 O2 Gas % TDCG

10 0 0 0 0 33 242 0 2 58254 3145 7 40 20 0 0 0 1 88 482 2 3 63510 5083 8 114 30 0 0 0 3 149 614 4 3 66845 7761 8 186 40 0 1 1 5 250 888 7 4 6914610574 9 285 50 0 1 2 9 350 1163 9 5 7279114052 9 394 60 0 2 3 11 443 1689 12 6 7437717980 9 478 70 0 3 3 13 569 2069 15 7 7789422043 10 605 80 0 7 5 16 639 2400 23 12 8079628131 10 700 90 0 14 9 24 805 3050 35 19 8509831772 11 847 95 0 24 17 32 938 4436 55 29 8702134229 11 1019 99 3 42 61 43 1222 7405 108 63 9220736874 12 1267

Gas Values in ppm v/v

35

Percentile Values of Voltage Transformers Percentile % C2H2 C2H4 C2H6CH4 CO CO2 H2 H2O N2 O2 Total GasTDCG

10 0 0 0 1 41 508 0 3 60764 2553 8 61 20 0 0 0 5 204 732 2 4 67123 5777 8 263 30 0 0 1 8 283 1089 5 5 70523 7905 9 339 40 0 1 2 10 372 1584 9 5 73116 10491 9 440 50 0 1 3 12 476 2043 12 6 75500 13680 9 527 60 0 2 3 14 558 2392 17 8 77062 16331 10 629 70 0 5 4 16 645 2782 24 10 79688 19774 10 718 80 0 10 6 20 750 3586 36 14 82113 25700 10 808 90 0 17 10 27 938 4400 56 22 87062 33176 11 1036

90 IEC low 4 20 - - - - 70 - - - - - 90 IEC high 16 30 - - - - 1000 - - - - -

95 0 42 18 33 1105 5933 126 32 88867 34914 11 1180 99 6 68 42 39 1353 9745 197 55 10087137210 12 1435

Percentile Values of Bushings Percentile % C2H2 C2H4 C2H6CH4 CO CO2 H2H2O N2 O2 Gas %TDCG

10 0 0 0 2 25 261 9 3 49151 351 5 60 20 0 0 1 3 51 437 17 3 58803 690 6 95 30 0 1 2 6 91 593 25 3 62660 1185 7 192 40 0 1 3 8 127 824 31 4 65746 1791 8 273 50 0 2 6 11 170 1026 38 5 71052 2659 8 355 60 0 2 9 13 256 1302 44 6 75325 4499 9 480 70 0 4 15 19 394 1614 59 6 78671 7555 9 584 80 0 9 28 27 550 2254 139 11 84108 12368 9 676 90 0 17 56 42 751 3065 278 17 90896 25649 10 880 95 0 20 71 61 937 4953 370 21 97946 29328 11 1136

95 IEC 2 30 70 40 1000 3400 140 - - - - - 99 16 27 202 116 111512862441 63 10455630999 11 1430

Gas values in ppm v/v

36

APPENDIX: 3 The following values are from IEC 60599 Publication: 1) Instrument transformers: (CT and VT) Ranges of 90% typical concentration values observed in Instrument transformers. Transformer Type

H2 CO CO2 CH4 C2H6 C2H4 C2H2

CT 6-300 250-1100 800-4000 11-120 7-130 3-40 1-5

VT 70-1000

20-30 4-16

2) Bushings (condenser and non- condenser type)

Ranges of 95% typical concentration values observed in Bushings. H2 CO CO2 CH4 C2H6 C2H4 C2H2

140 1000 3400 40 70 30 2

All values in ppm (V/V)

37

7 REFERENCES

[1] Evaluation of the Effectiveness of Dissolved Gas Analysis on Bushings, Colin Clark, Mike Lau, BC Hydro, Doble Conference Proceedings 2004.

[2] H. Schellhase, D. Pugh, "Maintenance-Free Load Tap Changer (LTC)", EPRI – Substation Equipment Diagnostics Conference IX, New Orleans, Louisiana, February 18–21, 2001.

[3] Research and Testing of Insulating Oils made from Canadian Paraffinic Crudes, CEA/EEMAC Study RP-77-37, 1978

[4] “Recent developments in DGA interpretation”, CIGRE TF 15/12-01-11 [5] V.Sokolov et al: “On-site partial discharge measurements on power transformers”, Doble

Client Conference, 2000. [6] Hubris: “Gassing behavior of different insulating liquids for transformers”, Electra, No.188,

pp.20-41, Feb.2000. [7] Foss, Transformer Paper in Oil Water Diffusion Time Constants, Presentation to the IEEE Insulating Fluids Sub-Committee, April 16, 2002 [8] H.Borsi : “gassing behavior of different insulating liquids for transformers”, Electra, No.188,

pp.20-41, Feb.2000.

[9] "Bushing Failure Rates/Mechanisms etc" by J Stead. Weidmann 2002 LV Conference Presentation.

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