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Table of Contents
Continuous Moisture-in-Oil Sensing: Field Applications for the Power Industry ...1
Lance R. Lewand and Paul J. Griffin
Dissolved Gas Analysis — Past, Present and Future ...8
Fredi Jakob, Ph.D.
New Insulating Oils: Alternative to Transformer Oil ...12
David W. Sundin, Ph.D.
Using Analytical Techniques to Determine Cellulosic Degradation in Transformers ...15
Lance R. Lewand
Understanding Water in Transformer Systems ...18
Lance R. Lewand
Which Insulating Oil Analytical Tests to Request and When ...22
Lance R. Lewand
Choosing a Sample Container for Transformer Oil Analysis ...26
Lance R. Lewand
OCB Diagnostics ...28
Fredi Jakob, Ph.D., Karl Jacob, P.E., Simon Jones, Rick Youngblood, and Alex Salinas
Sampling Transformer Oils —
Part 1 – How and Why to Take a Good Sample ...34
Lance R. Lewand
Sampling Transformer Oils —
Part 2 – Sampling Practices and the Science of Sampling
...37
Lance R. Lewand
Sampling Transformer Oils —
Part 3 – Retrieving the Actual Sample ...40
Lance R. Lewand
Insulating Oils
Handbook
Insulating Oils Handbook
Table of Contents (continued)
Corrosive Sulfur in Transformer Systems ...43
Lance R. Lewand
Sources of Sulfur in Transformer Systems ...47
Lance R. Lewand
Hot Oil Reclamation: Why Is It Necessary? ...50
Scott D. Reed
Use of Gas Concentrations Ratios to Interpret LTC Dissolved Gas Data ...58
Fredi Jakob, Ph.D., Karl Jakob, P.E., Simon Jones, and Rick Youngblood
The Negative Effects of Corrosive Sulfur on Transformer Components ...62
Lance R. Lewand
Nomograph for LTC-DGA Data Interpretation ...65
Fredi Jakob, Ph.D., Karl Jakob, P.E., Simon Jones, and Rick Youngblood
Condition Assessment of Oil Circuit Breakers and Load Tap-Changers
by the Use of Laboratory Testing and Diagnostics ...7
Lance R. Lewand and Paul J. Griffin
Natural Ester Dielectric Liquids ...73
Lance R. Lewand
Laboratory Testing of Natural Ester Dielectric Liquids ...77
Lance R. Lewand
Gassing Characteristics of Transformer Oil Under Thermal Stress ...80
Lance R. Lewand and Paul J. Griffin
Condition Assessment of Transformers — Analysis of Oil Data and Its Quality ...84
Lance R. Lewand
Recent Applications of DGA ...86
Karl Jakob, P.E. and Fredi Jakob, Ph.D.
Passivators — What They Are and How They Work ...90
Lance R. Lewand
What is Sludge? ...93
Lance R. Lewand
Metals Analysis in Transformers, Load Tap-Changers and Oil Circuit Breakers ...95
Lance R. Lewand
Testing for Corrosive Sulfur Effects ...98
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Insulating Oils Handbook
1
Continuous Moisture-in-Oil Sensing:
Field Applications for the Power Industry
PowerTest 2000
(NETA Annual Technical Conference)
Presenters
Lance R. Lewand and Paul J. Griffi n Doble Engineering Company
Th is paper discusses the application of a continuous moisture-in-oil sensor that operates in dielectric fl uids, such as transformer mineral oils. Th e sensor can be used to help in the assessment of the condition of transformers and for oil processing.
Introduction
Th e principal reason for developing a continuous mois-ture-in-oil sensor is that moisture continues to be a major cause of problems in transformers and a limitation to their operation. Excessive moisture is particularly problematic in transformers as it aff ects the dielectric breakdown strength of the insulation, the temperature at which water vapor bubbles are formed and the aging rate of the insulating materials [1]. In the extreme case, transformers can fail because of excessive water in the insulation. Th e dielectric breakdown strength of the paper insulation decreases sub-stantially when its water content rises above 2 to 3 % by weight. Th e dielectric breakdown voltage of the oil is af-fected by the relative saturation (RS) of water in oil which is constantly changing in a transformer environment. Th e maximum loading that is possible while retaining reliable operation (i.e., preventing the formation of water vapor bubbles) is a function of the insulation water content. For example, dry transformers (<0.5% water in paper) are much less susceptible to bubble evolution. In this case emergency loading at hot-spot temperatures below 180 C may be pos-sible with little risk of bubble formation. In contrast, a wetter transformer, with 2.0% moisture in the paper, runs the risk of bubble formation with hot-spot temperatures as low as 139 C under the same conditions [1]. A more long-term problem is that excessive moisture accelerates the aging of the paper insulation, with the aging rate being directly pro-portional to the water content. Th at is as the water in paper content doubles the aging rate of the paper also doubles [2]. For these reasons it is important to have an assessment of the moisture content of the insulation systems and to maintain transformers in a reasonably dry state.
In addition, the success of oil or transformer drying (dehydration) techniques is often measured by the amount of water remaining dissolved in the oil after processing. Th e historical approach to the detection of water in these circumstances has been by the Karl Fischer titration, com-monly referred to in North America as ASTM Test Method D 1533B. Th is chemical analysis has three major drawbacks: it cannot be developed into a continuous measurement; it can be plagued with a number of introduced errors most of which result from sampling and sample containers; and cer-tain chemical interferences produce erroneous results [3].
Principles of Moisture Detection
Th e Doble moisture-in-oil sensor (DOMINO ) mea-sures the capacitance of a thin-fi lm polymer. Th e capacitance changes proportionally to the change in RS of water in the oil. Relative saturation, expressed in units of percent, is the concentration of water (Wc) in the oil relative to the solu-bility (S) or concentration of water the oil can hold at the measurement temperature, as shown in Equation 1.
(Equation 1) RS = Wc /S (100%) Where: Wc is in ppm wt./wt.
S is in ppm wt./wt.
Th e sensor converts the measured RS to a concentration, stated in parts per million in mg/kg (ppm wt./wt.). To be able to perform this calculation the instrument measures both the temperature and the capacitance of the thin-fi lm polymer and converts it to RS. Equation 2 provides the conversion for mineral oil:
(Equation 2) Log So = -1567/K + 7.0895
Where: So is the solubility of water in mineral oil K is the temperature in Kelvin ( C + 273)
Th e structure of the moisture-in-oil sensor is shown in Figure 1. Th e moisture-in-oil sensor is composed of an upper and lower electrode, a thin-fi lm polymer and a sup-port base.
Figure 1 — Structure of Moisture-In-Oil Sensor
Water vapor penetrates the upper electrode and reaches the thin-fi lm polymer. Th e amount of water vapor absorbed is dependent on the RS of water in the oil. Because the sen-sor relies on the movement of water molecules to and from the thin-fi lm polymer, oil fl ow around the sensor greatly facilitates this process. Little or no oil fl ow around the sen-sor will give low readings below the true water content. Th e polymer used for this application is dispersive, that is, its di-electric constant changes with changing water content. Th e capacitance of the polymer, which is the dielectric constant of the material divided by the dielectric constant of vacuum (which is 1), is used to determine the RS of water in the dielectric liquid. Th e moisture and temperature sensors are mounted on the end of a probe, which is placed directly in the oil. A signal cable transmits the capacitance changes from the probe to a NEMA 4 weatherproof transmitter housing which contains the electronics.
The Importance of a Continuous
Measurement in Transformers
Th ere are signifi cant advantages of having continuous moisture measurements. Moisture is in a dynamic state, migrating between oil and cellulosic materials and within the cellulosic materials, varying with temperature, thermal history, geometry and thickness of the solid insulation, mois-ture content, and other factors (Figure 2). Taking a moismois-ture sample on a periodic basis without consideration of these factors can provide a false sense of reliability. Real time rat-ings and condition assessment of transformers requires real knowledge of the moisture content of the solid insulation. Figure 2 clearly demonstrates how the moisture content in oil from an operating transformer can vary signifi cantly from hour to hour during the course of a day.
Figure 2 — Continuous Moisture Detection in a Transformer
Excessive moisture in the oil may occur in relatively dry transformers as the moisture migrates between the oil and paper during extreme thermal transients. Moisture is forced from the solid insulation while increasing in temperature. Fortunately, the oil can hold more moisture with increasing temperatures and therefore the percent saturation of water in oil does not rise excessively. A problem can occur during cooling because the moisture does not return to the cellulosic materials quickly enough. Th e ability of the oil to hold mois-ture decreases at the cooler temperamois-tures during this cycle, resulting in a high RS of moisture in oil and reduced di-electric breakdown voltage [4]. Continuous moisture-in-oil measurements made in a laboratory model experiment with very wet paper insulation are shown in Figure 3. Note how the RS of moisture in oil is driven up during the cooling cycle and remains high. In eff ect the moisture is trapped in the oil, as the diff usion into the paper is so slow. In a similar model with dry paper insulation the water content as mea-sured in RS quickly recovered to about the same baseline value regardless of temperature (Figure 4).
Lower electrodes
Upper electrode Active thin film
polymer Supporting glass substrate 0 2 4 6 8 10 12 14 1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101 105 109 113 117 121 125 129 133 137 Hours
Relative Saturation, % and Water Content, ppm
0 10 20 30 40 50 60 70 Temperature, Degrees C Relative Saturation Water Content, ppm Bottom Oil Temperature
Figure 3 — Temperature Cycling in Very Wet Insulation Model
Temperature, Degree C
Measured Relative Saturation in Oil, %
0 10 20 30 40 50 60 70 80 90 100 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360
Elapsed Time, Hours
20 40 60 80 100 120 140 160 180 200 220 %RS Temp.
Insulating Oils Handbook
3
0 4 8 12 16 20 24 28 32 36 40 44 48 0 4 8 12 16 20 24 28 32 36 40 44 48 52 56 60 Water Content, ppm. wt./wt.Dielectric Breakdown Voltage, kV
0 4 8 12 16 20 24 28 32 36 40 44 48 0 10 20 30 40 50 60 70 80 90 100 Water Content, % RS @ 22 C
Dielectric Breakdown Voltage, kV
Figure 4 — Temperature Cycling in Drier Insulation System Model
To properly maintain and operate transformers, an under-standing of the eff ects of moisture on the dielectric break-down strength of the electrical insulating liquids is necessary. Th e moisture content reduces the dielectric breakdown volt-age of insulating liquids. It is common practice to measure moisture content as a concentration (ppm). Th e correlation between the water content in new, fi ltered, mineral oils at room temperature and the dielectric breakdown voltage using ASTM method D 1816 (0.04 inch gap) is given in Figure 4. Of course, the dielectric breakdown voltage will also be a function of the number and type of particles and their conductivity, not just the water content.
Recall that the relative saturation of water in oil is the water content at a given temperature divided by the solubil-ity of water in the oil at the same temperature. Taking the same dielectric breakdown voltage data as given in Figure 5 and converting it to RS provides a much straighter curve except at the extremes. Th is is shown in Figure 6. It is evident that there is a better correlation between RS and dielectric breakdown voltage than with moisture concentration and dielectric breakdown voltage.
Figure 5 — Dielectric Strength Versus Water Content
Figure 6 — Dielectric Strength Versus Relative Saturation (RS)
Th e solubility of water in oil is an exponential function of the oil temperature [4] as shown in Table 1. It is clearly apparent that, as the temperature of the oil increases, the amount of water that can be dissolved in the oil increases tremendously.
TABLE 1
Water in Oil Solubility As a Function of Temperature
Oil Temperature Water Content
in Oil, ppm in Silicone, ppmWater Content
0°C 22 88 10°C 36 125 20°C 55 174 30°C 83 237 40°C 121 316 50°C 173 414 60°C 242 534 70°C 331 678 80°C 446 850 90°C 592 1052 100°C 772 1287
A simple example can be used to illustrate that the di-electric breakdown voltage of insulating oils is proportional to the relative saturation of water in oil rather than the con-centration in ppm. First, a dielectric breakdown test set and cup is placed in a temperature and humidity-controlled envi-ronment. Th e humidity is controlled so the concentration of water in the oil is held constant at 30 ppm. Th e temperature starts at 100 C and the fi rst dielectric breakdown voltage measurement is made. At 100 C the solubility of water in oil is about 772 ppm. Th e relative saturation of water in oil is therefore about 4% and the dielectric breakdown voltage of a well-fi ltered oil would be quite high. Now the temperature of the chamber is reduced to room temperature or about
0 1 0 2 0 3 0 4 0 5 0 6 0 7 0 8 0 9 0 0 2 0 4 0 6 0 8 0 1 0 0 1 2 0 1 4 0 1 6 0 1 8 0 2 0 0 2 2 0 2 4 0 2 6 0 2 8 0 3 0 0 3 2 0 3 4 0 3 6 0 E la p s e d T im e , H o u rs 0 10 20 30 40 50 60 70 80 90 %RS
Temp. Temperature, Degree C
22 C. Th e solubility of water in oil is about 60 ppm and the relative saturation is 50%. Th e dielectric breakdown voltage would be expected to be about one half of what it was when the relative saturation was very low. If the temperature is cooled to 0 C and the dielectric breakdown voltage mea-surement is made, the results should be quite low because the solubility of water in oil at this temperature is about 22 ppm. As the water content in the oil is higher than this, the water forms an emulsion (the oil will appear cloudy2 with the suspended water) and begins to form condensation (Figure 7). During all this time the concentration of water in oil has not changed (Table 2).
Figure 7 — Low RS Oil Versus High RS Oil
TABLE 2
Relationship Between Dielectric Strength
and Water Content
Oil
Temperature Water Content, ppm SaturationRelative Dielectric Strength
100°C 30 3.9% High
22°C 30 50% About half
of high
0°C 30 >100% Very Low
Transformers are more complicated systems than given in this simple example. However, the same basic principles apply for the dielectric breakdown strength of the liquid dielectric. Th at is, it remains a function of the relative satu-ration of water in the oil. During the cool-down cycle of a thermal transient in a transformer some of the moisture returns to the paper and some of the moisture remains in the oil. Th e relative saturation of water remaining in the oil will infl uence its dielectric breakdown voltage. For this reason continuous measurement can be used to detect conditions in which moisture distribution is a problem.
The Importance of an In-line
Moisture Measurement in Oil Processing
Applications
DOMINOTM can be used for continuous monitoring
of oil processing applications. It was determined that the following attributes would be required in a moisture-in-oil sensor used for these applications:
Provides a fast, continuous measurement Have the ability to withstand high fl ow rates
Can be mounted directly in the oil processing equip-ment
Performance is not aff ected by pressure, vacuum, and temperature
Can be adapted to a variety of systems
Th e application of a continuous moisture-in-oil sen-sor would greatly benefi t the user in determining the end point of any oil processing activity involving the removal of dissolved water from the oil. However, additional benefi ts could also be gained such as:
Determination of fi lter bleed-through
Elimination of taking oil samples for water content by chemical analysis
Determination of oil processing effi ciency
Determination of the amount of water removed by fi ltering and/or dehydrating processes
Determination of the eff ectiveness of fi eld-drying a transformer
Determining the proper time to change fi lter cartridges due to fi lter bleed-through is a concern during transformer oil processing. Changing them is usually based on dif-ferential pressure or a pressure increase, which can result from excessive moisture, or particulate contamination. Th is is often late in the process, when high amounts of dissolved water is already in the processed oil. Th e purpose of a continuous in-line moisture-in-oil sensor would be to accurately measure the amount of water in the processed oil, clearly indicating when fi lters should be changed, and therefore speeding up the drying process. In most cases, a moisture-in-oil sensor would indicate the need for a fi lter change long before a pressure increase criterion would be reached. Typically the water content in ppm remains fairly constant at some low value while the fi lter is most eff ec-tive, and then starts to increase gradually. A reasonable end point can be chosen to change the fi lter before it becomes ineff ective. Monitoring of the diff erential pressure is still a valuable practice as fi lters can be plugged from particulate contamination and free water.
One of the most benefi cial results from the use of an in-line continuous moisture-in-oil sensor is the elimination of the need to take periodic samples for Karl Fischer titra-tion measurements (and the associated chemicals and their
Visual Appearance, Cloudy Water Content, 30 ppm
Temperature, 0°C, High RS Temperature, 50°C, Low RS
Visual Appearance, Clear
Insulating Oils Handbook
5
disposal). Th e algorithm used in this particular moisture-in-oil sensor converts relative saturation of water in oil and temperature into the concentration of water in ppm, and was determined initially by using the Karl Fischer titration. Figure 8 demonstrates how closely the two measurements are related to each other.
Figure 8 — Moisture-In-Oil Sensor Versus Karl Fischer Titration
Th e accuracy of this particular sensor in ppm varies with the temperature of the measurement because it is a conver-sion from RS and not a direct ppm measurement. Table 3 below provides some useful values. For very aged oils the relationship between RS and concentration (ppm) may need to be determined experimentally.
TABLE 3
Accuracy of Moisture-In-Oil Sensor
TEMPERATURE % Accuracy, RS Accuracy, PPM0°C ± 1% ± 0.25 10°C ± 1% ± 0.40 20°C ± 1% ± 0.60 40°C ± 1% ± 1.25 60°C ± 1% ± 2.50 80°C ± 1% ± 4.50
Th e moisture-in-oil sensor can be used to estimate the effi ciency of an oil dehydrating process using vacuum or fi lters. In the case of vacuum dehydrating, the inlet and outlet oil can be monitored to determine the best fl ow rate, dwell time, applied vacuum, temperature, and if other mechanical aspects of the process are functioning adequately. Th is can be done by comparing the diff erence in the water content of the oil at the inlet and outlet of the processor. Th e greatest diff erence in water contents will indicate optimum effi ciency. Once the most effi cient processing conditions have been set, the moisture-in-oil sensor can then be used to continuously monitor the process. If the effi ciency begins to decline, then
appropriate actions can be taken to improve it. Th e moisture-in-oil sensor can be used in a similar fashion to determine the best operating conditions for the use of fi lters.
Calculating the total amount of water removed can be a useful measure of dehydrating eff ectiveness. It is quite simple for oil in a storage tank. For instance, using Equation 3, it can be determined that a fi ltering or dehydrating process which removes 35 ppm of water (diff erence between inlet and outlet measurements) on 10,000 gallons of oil would remove 1.2 liters of water.
(Equation 3) Wt = 3.31X10-6 V
oil (Ci –Co)
Where:
Wt = Th e total amount of water removed in liters
Voil = Th e volume of oil in gallons
Ci = Th e inlet concentration of water in oil in ppm wt./wt. from the moisture-in-oil sensor
Co = Th e outlet concentration of water in oil in ppm wt./wt. from the moisture-in-oil sensor
In the example the calculation would be as follows:
Wt = 3.31X10-6(10,000gallons)(40–5)=1.2 liters of water
Th e eff ectiveness of fi eld drying of the transformer, whether the process is conducted out of service or in-ser-vice, is much more diffi cult to assess than drying the oil alone. Th is is because the large mass of cellulosic insulation (paper, pressboard, wood structural members, etc.) contains almost all of the water in a transformer and the moisture distribution is uneven and unknown. A reasonable estimate can be produced before and after processing if the following variables are known:
Volume of oil Mass of paper
Concentration of water in ppm at a known temperature (preferably one that is > 50 C)
At higher constant temperatures it is possible to estimate the average moisture content of the cellulosic insulation [6,7]. For example, if a transformer has 10,000 gallons (37,850 liters) of oil, 9125 pounds (4148 kg) of paper, and 30 ppm of water in oil while maintained at 70 C (RS = 9.0), then the calculated amount of water in the oil and paper is as follows:
Th e oil contains about 1.0 liter of water Th e paper contains about 78.5 liters of water
Th e entire system would have an estimated total volume of approximately 80 liters
Th e amount of water in oil was determined by Equation 3, where:
Ci = the water-in-oil content
Co = 0 0 10 20 30 40 50 60 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Samples Water Content, ppm
Th e amount of water in the paper is estimated by multi-plying the mass of paper times the concentration of water in the paper in percent.
If the amount of paper is unknown it can be estimated from the following:
Shell-form transformers, the paper mass = oil mass/3 Core-type transformers, the paper mass =oil mass/8 Core type transformers with enameled wire insulation, the paper mass = oil mass/20
Th e amount of water in the paper can be calculated by two means, using an equation or a family of curves. Th e equation is as follows:
(Equation 4)
Cp = {2.17x10-5x[(RS
tox10-2)(Ps)]0.6685}xe4726 (Tto+273)
Where:
Cp = moisture content in the paper in %
RSto = relative saturation of water in oil at temperature,
Tto
Ps = Th e saturation vapor pressure at temperature, Tto (from published data, see
Reference 8). Th e values are given in mm of Hg and need to be converted to
atmospheres by dividing by 760 mm Hg/atmosphere.
e = natural log
Tto = top oil temperature
Th e amount of water was calculated as 1.9% of the mass of cellulosic materials, which gives a mass of water of 173 pounds (78.5 kg). Th is mass can then be easily converted to liters of water by multiplying by 0.454 liters/pound for a volume of 78.5 liters. Th e other way to calculate the amount of water in paper is to use equilibrium isotherm curves, taking the concentration of water in oil and the top oil temperature to fi nd the equilibrium value [4].
Once the drying process has been completed the same estimation process for moisture in the cellulosic materials can be repeated. Th is should be done after the transformer has been at an elevated temperature for at least three days without processing. Th e diff erence in the amount of water before and after fi ltering is the quantity removed.
Another way to determine how much water is removed by processing each day is to use Equation 3. Th e fl ow rate can be used to determine the volume of oil processed, and the inlet and outlet water contents (while fairly constant) provides the concentration of water removed. If the inlet water-in-oil content changes signifi cantly then the calcula-tion should be restarted and the volumes of water removed summed for each set of calculations. Th e effi ciency of the process can readily be observed by examining the diff erence between the inlet and outlet water content [7].
In the example above, the paper contained 1.9% water or 78.5 liters at the start of the processing. Ideally the water content of the paper would be reduced to a fi nal concentra-tion of 0.5% or lower. Th is would require removal of at least 58 liters of water.
Conclusions
A new moisture-in-oil sensor, DOMINOTM, has been
developed to provide continuous in-situ measurements of dissolved water in oil. Th e measurement of the capacitance of a thin-fi lm polymer is used to detect the relative satura-tion (RS) of water in oil. Th e relative saturasatura-tion of water in oil along with the measured value for temperature are used to calculate the concentration in ppm (wt./wt.).
Current applications in which this moisture-in-oil sensor can be used are:
Continuous moisture measurement in transformers On-line/off -line oil processing applications
Determination of fi lter bleed-through
An alternative to taking oil samples for water content by chemical analysis
Determination of oil processing effi ciency
Determination of the amount of water removed by fi ltering and/or dehydrating processes
Determination of the eff ectiveness of fi eld-drying a transformer
References
[1] Griffi n, P. J. “Water in Transformers – So What!”, National Grid Condition Monitoring Conference, May 1996.
[2] Lewand, L. R. and Griffi n, P. J., “How to Reduce the Rate of Aging of Transformer Insulation”, NETA
World, Spring 1995, pp. 6-11.
[3] Lewand, L. R. and Griffi n, P. J., “Transformer Case Studies”, Proceedings of the Sixty-Six Annual
Interna-tional Conference of Doble Clients, 1999, Sec.5-7.
[4] Griffi n, P. J. “How to Prevent Rain in Power Trans-formers”, ASTM Standardization News, November 1991, ASTM, Philadelphia, PA, pp. 30-33.
[5] Griffi n, P. J., Bruce, C. M., and Christie, J. D. “Com-parison of Water Equilibrium in Silicone and Min-eral Oil Transformers”, Minutes of the Fifty-Fifth
An-nual International Conference of Doble Clients, 1988,
Sec. 10-9.1.
[6] “Estimating the Water Content of Cellulosic In-sulation”, MKT-AB-12, Rev A, Doble Engineering Company DOMINOTM Application Bulletin,
No-vember, 1999, 4 pp.
[7] “Transformer Oil Field Processing Applications”,
MKT-AB-16, Rev A, Doble Engineering Company
DOMINOTM Application Bulletin, November, 1999,
Insulating Oils Handbook
7
[8] “Vapor Pressure of Water Below 100 C” In CRC
Handbook of Chemistry and Physics, Ed. Robert C.
West, Boca Raton, FL. CRC Press Inc., 1978-1979, P. D-232.
Lance Lewand received his Bachelor of Science degree from St. Mary’s College of Maryland in 1980. He has been employed by the Doble Engineering Company since 1992 and is currently the Laboratory Manager for the Doble Materials Laboratory and Product Manager for the DOMINO®. product line. Prior to his present position at Doble, he was Manager of the Transformer Fluid Test Laboratory and PCB and Oil Services at MET Electrical Testing in Baltimore, MD. Mr. Lewand is a member of ASTM Committee D 27.
Paul J. Griffi n received his BS degree at the American International College and his MS at the University of Rhode Island. He has been em-ployed by the Doble Engineering Company since 1978 and is currently Vice President of Laboratory Services. He is secretary of the Doble Oil Committee, a member of ASTM committee D 27, US Technical Advisor to IEC TC10 for Fluids for Electrotechnical Applications, member of the IEEE Insulating Fluid subcommittee of the Transformer committee, and a member of the CIGRE Working Group 15.01 Fluid Impregnated Insulating Systems.
I. Introduction
It has been well over thirty years since dissolved gas analy-sis, DGA, was introduced as a diagnostic tool for monitoring mineral oil fi lled transformers. It is now universally accepted as the method of choice to locate incipient thermal and electrical faults. DGA methodology and applicability have evolved signifi cantly since its inception. Th e evolutionary development includes new laboratory methods, on-line DGA, application to additional types of fl uid fi lled equip-ment, application to dielectric fl uids other than mineral oil and new diagnostic interpretation protocols.
At this time the ASTM has approved two procedures for laboratory DGA and a third method is on the verge of approval. Devices, which periodically or continuously moni-tor one or more gas in oil concentrations, are available for on-line analysis. DGA was originally developed for trans-formers, but it is now being applied to load tap changers, oil fi lled circuit breakers, oil fi lled bushings and cable oil. Data interpretation methods have been extensively developed for transformers fi lled with mineral oil and IEEE is currently developing a guide for silicone fl uid fi lled transformers.
II. Laboratory Methods
ASTM procedure, D 36121, provides two different
methods for the extraction of dissolved gases from dielectric fl uid. Method D 3612-A involves an extraction process that precedes the subsequent gas analysis. Th e dielectric fl uid is delivered into a previously evacuated glass apparatus and is stirred for a suffi cient time to extract most of the dissolved gases. Th e volume of the evacuated glassware must be large in comparison to the volume of dielectric fl uid so that most of the dissolved gases leave the fl uid phase. Th e evolved gas is compressed and the volume and temperature are measured. Th en, one or more aliquots of the gas are separated and quantifi ed with a gas chromatograph. Each gas concentra-tion in the oil is reported in ppm by volume. ASTM 3612-A is time consuming and labor intensive, but it has low
detec-tion limits and generates reproducible data. Mercury is used in the extraction apparatus so precautions must be taken to minimize worker exposure to mercury vapors.
ASTM D 3612-B uses direct injection of an oil sample onto a heated gas stripping column that is in series with a separation column, both of which may be contained within a single gas chromatograph. Th e advantages of this method are speed and elimination of potential mercury health hazards. One disadvantage is that method B cannot be used with Silicone fl uids because excessive foaming will damage the separation columns. Also, since fault gases are very soluble in mineral oil the extent of gas extraction may not be as complete as in the two stage method. Th e ASTM docu-ment states, “Th e limit of detection for hydrogen specifi ed in Method B is higher than that specifi ed for Method A. Th is could eff ect the interpretation of results when low levels of gases are present”.1 ASTM D 3612, which contains a
comparison of the detection limits of methods A and B, is summarized in Table 1.
Table 1
Minimum Gas Detection Limits, ppm
vol1Gases Method D 3612-A Method D 3612-B
Hydrogen 5 20
Hydrocarbons 1 1
Carbon Oxides 25 2
Atmospheric Gases 50 500
New DGA methodology that involves a two stage pro-cess2 has been developed and is being reviewed by ASTM
committee D-27 (Proposed Designation D 3612-C). Th e fi rst stage of the proposed “headspace” method involves a partitioning of dissolved gases between oil and an inert gas, argon. Oil samples are introduced into a sealed container that has been purged with argon. Samples are then heated and vigorously agitated for an extended period of time. Ostwald partition coeffi cients are used to correlate gas
Dissolved Gas Analysis —
Past, Present and Future
PowerTest 2000
(NETA Annual Technical Conference)
Fredi Jakob, Ph.D. Analytical ChemTech International, Inc.
Insulating Oils Handbook
9
concentrations in the headspace of the sample container with the initial gas concentrations in the oil. Th e second stage involves analysis of the evolved gases with a gas chromatograph. Th e advantages of this headspace method include automation of the extraction and analysis process and elimination of mercury. Detection limit comparisons between the headspace method and D 3612-A are being developed. One area of concern is potential variability of Ostwald coeffi cients with oil type, though most believe the diff erence of results due to this factor is not signifi cant.
III. On-Line DGA
In-time maintenance of electrical equipment, performing maintenance on only those units that require it, is a desirable goal. In order to fully implement this objective, equipment would have to be eff ectively monitored on an ongoing basis. Since DGA is accepted as an excellent diagnostic monitor-ing tool a great deal of eff ort has been expended to develop on-line DGA. Th e two steps required to implement this are automated separation of the fault gases from the oil followed by quantitative analysis. One or more gases can be extracted from the oil and subsequently analyzed with a chromatograph, an infra-red spectrometer or a mass spectrometer. Separation of the gases from the oil can be achieved with a semi-permeable membrane or a mechanical device. Th e small mobile hydrogen atoms, and to a lesser extent other small molecules such as CO, are most readily separated. Th e hydrogen can then be measured. Fortunately, hydrogen is formed with any type of fault, partial discharge, heating or arcing and the measurement of this gas can be used to continuously monitor the condition of a transformer. Hydrogen detection methods are best used as trigger devices to indicate when a laboratory DGA is appropriate.
Mechanical extraction devices for separation of gases from oil have also been developed. Oil is fed into a cylinder fi tted with a piston that is moved up and down. On the down stroke headspace is created in the cylinder and the gases partition between the oil and the headspace. During the compression stoke the gas is pushed into a reservoir and the cycle is repeated. Th is multiple stage extraction procedure is potentially more eff ective than a single stage extraction such as that used in ASTM D 3612-A . Th e extracted gases can then be separated and analyzed by gas chromatography or quantifi ed without prior separation by infra-red or mass spectroscopy .
On-line DGA is theoretically feasible but reliability, detection limits and economic issues must still be resolved before the method is widely implemented. Detection of a limited number rather than all of the gases may be a suf-fi ciently viable compromise.
IV. Applicability of DGA
A. Fluid Types
Th ermal or electrical faults release energy that will result in the partial molecular destruction of dielectric fl uids. Th e extent of the molecular rearrangement depends on the available energy and the nature of the dielectric fl uid. Faults
will produce gases in mineral oils, high molecular weight hydrocarbons, PCB’s, silicone fl uids, perchlorethylene and other dielectric fl uids. Since DGA interpretation is empiri-cal in nature it has only been eff ectively applied to dielectric fl uids that have been extensively studied. Th e current IEEE guide3, 57.104, covers the application of DGA to mineral
oils only. High molecular weight hydrocarbons, also known as less fl ammable hydrocarbons, contain similar molecules to those present in conventional mineral oil and produce the same gases under similar fault conditions. Th e IEEE guide is applicable, without modifi cation, for these fl uids. Silicone fl uids produce the same fault gases as mineral oils when they are thermally or electrically stressed, but relative concentrations and fault gas concentration ratios are dif-ferent. A separate IEEE trial-use guide, P1258, has been developed for these fl uids4. IEEE guides for the other fl uids
are not currently available.
B. Equipment Types
DGA was initially developed to monitor transformers and the success of this method is well known. Fault condi-tions can exist in any type of electrical equipment and if this equipment contains dielectric fl uids, fault gases will be produced. Table 2 shows the correlation between fault types and the various fault gases.
Table 2
Fault Gases
Gases Indication
Hydrogen Partial discharge, heating, arcing Methane, Ethane, Ethylene “Hot Metal” gases
Acetylene Arcing
Carbon Oxides Cellulose insulation degradation
1. Load Tap Changers
When a load tap changer, LTC, operates arcing occurs and the expected fault gases, acetylene and hydrogen, are produced. One might initially assume that the presence of these gases masks the gases produced by other faults. Coking and misalignment of contacts are the most com-mon problems that occur in LTCs. Coking is a cumulative problem that starts with an initial deposition on the contact surfaces, which results in increased contact resistance, fol-lowed by additional carbon build up on the contacts. Th is process leads to exponentially increased heating or “thermal runaway” and carbon build up. Youngblood 5 was one of the
fi rst investigators to realize that the coking problem would result in the production of the “hot metal gases,” methane, ethane and especially ethylene. Th e concentration of these gases depends on a number of variables including breath-ing type, manufacturer, model type, etc. Generic fault gas threshold values, similar to those in the IEEE guide for transformers, have been developedby Youngblood and are given in Table 3.
Table 3
LTC Monthly Watch Criteria
5LTC Type Hydrogen Acetylene Ethylene
Free or Desiccant
Breather >1500 ppm >1000 ppm >1000 ppm Sealed >5000 ppm >9000 ppm >1200 ppm Vacuum >10 ppm >5 ppm > 100 ppm
Charles Baker6 and others have developed manufacturer
specifi c fl ag points and this approach, which is illustrated in Table 4, is probably the most promising.
Table 4
Equipment Specifi c Action Levels
(McGraw Edison LTC 550)
Hydrogen Methane Ethane Ethylene Acetylene CO CO2
LT1 100 100 100 500 100 100 150
LT2 250 200 200 1200 200 500 300
LT3 500 400 400 2000 400 1000 3000
LT1 = Abnormal LT2 = High LT3 = Very High A typical LTC case history is documented below:
AC TLH-21 138KV x 12KV 50 MVA Free Breather Date: February 25, 1993
Date Mfr. Serial Number C2H2 CH4 C2H6 C2H4 H2 CO CO2
02/25/93 AC 018226580301 0 5 1 4 34 71 350
Th is unit was determined to be operating properly. Th e low concentrations of hydrogen and acetylene are considered normal for a free breathing unit. Th e unit was scheduled for annual testing.
Date: February 25, 1994
Date Mfr. Serial Number C2H2 CH4 C2H6 C2H4 H2 CO CO2
02/25/94 AC 018226580301 44 1812 576 3143 149 33 645
Th is unit was in “thermal runaway” when tested. Notice the high level of ethylene, which is the key gas for overheat-ing. Th is unit was already heavily coked when the DGA test was conducted. Th e unit was removed from service and repaired. Th e reversing switch and some moveable dial contacts were replaced.
Date: February 27, 1995
Date Mfr. Serial Number C2H2 CH4 C2H6 C2H4 H2 CO CO2
02/27/95 AC 018226580301 55 9 2 11 22 33 440
Th e unit is operating normally after completion of the repairs. Th e LTC was placed on a six month test interval based on its previous failure history.
2. Oil Filled Bushings
John Stead presented a paper at the 1996 Doble confer-ence7 showing how DGA could resolve confl icting Power
Factor results for two bushings from the same manufacturer. Th e DGA data for these two bushings is given in Table 5. Th is data clearly indicates that partial discharge is occurring in bushing 2. Th e low ratio of CO2 / CO indicates severe overheating of the paper in the bushing. Physical inspection confi rmed the interpretation of the DGA results.
Table 5
DGA Data for Two Bushings, ppm
7Gas Bushing 1 Bushing 2
Hydrogen 1705 19132 Oxygen 5546 4041 Nitrogen 68216 50767 Carbon Monoxide 441 537 Methane 146 1256 Carbon Dioxide 710 1459 Ethylene 1.8 11 Ethane 71 409 Acetylene <0.1 0.2
Removal of oil from a bushing is not encouraged by most manufacturers, but the practice is common in Europe.
3. Oil Filled Circuit Breakers
Application of DGA to oil circuit breakers, OCB’s, is under investigation by ACTI in cooperation with several utilities. Most OCB’s are free breathing and fault gas con-centrations could be very dependent on the sampling time. Other tests such as particle size distribution, particle types and metals in the oil are being evaluated for the identifi ca-tion of problem units.
V. Supplementary Tests
Carbon oxides are produced by the degradation of cel-lulose insulation or when oil is heated in the presence of oxygen. Th e extent of cellulose degradation is a critical fac-tor in estimating the condition and life expectancy of solid insulation. Levels of CO and CO2 and the ratio CO2 / CO can be used to indicate when further investigation of the cellulose condition is warranted. Th e two available methods are Degree of Polymerization, DP, and Furanic compound analysis. DP is more defi nitive, but this invasive procedure requires removal of paper samples from the equipment. Fu-ran analysis is a non-invasive procedure and is recommended if the DGA results indicate cellulose decomposition.
A very interesting example of the eff ect of transformer overheating was provided to ACTI by Mr. Charles Baker, South Carolina Electric and Gas Co8. Th e transformer in
question 33/13.8 kV was run for 4 days without operation of the fans and pumps. Th e main winding temperature of this three and a half year old transformer reached 1500 C.
Insulating Oils Handbook
11
Rates of cellulose degradation double for each 6-8 degree rise in temperature. If we assume a normal winding tem-perature of 900, the sixty degree rise in temperature would
correspond in a 210 (1024) increase in the rate of cellulose
decomposition. Four days at the elevated temperature would correspond to 4096 days, 11.2 years of normal operation. Th e transformer insulation would then be 14.5 years old. Th e laboratory analysis showed 0.45 ppm of 2-furfuraldehyde which correspond, using the Chendong equation, to a DP of 530 and an apparent operating time of 25 years. Th ere was no additional data to indicate if the transformer was over-heating during the fi rst three and a half years of operation. Baker has recently reported that the transformer failed.
VI. Future Developments
Proposed changes in DGA laboratory procedures have been noted above. IEEE Guide 57.104 was last revised in 1991 and is currently being revised once more. Th e commit-tee is proposing a two step process for utilization of DGA laboratory data. Th e current thinking is that there should be one set of criteria for interpretation of the fi rst DGA result (proposed Table 1) and a second set of criteria for subsequent tests (proposed Table 2). Current deliberations include the concentrations of fault gases that will be classifi ed as “nor-mal” and levels that lead to a recommendation to monitor the transformer at shorter intervals. Once it is determined that one or more gases have exceeded these “normal” levels then the rates of fault gas generation should be determined. Table 2 will then tabulate IEEE recommendations for sub-sequent test intervals and operational procedures.
References
1. ASTM, Annual Book of ASTM Standards, Volume 10.03, D 3612-96.
2. Jalbert, J. and Gilbert, R. “Comparison Between Head-space and Vacuum Gas Extraction Techniques for the Gas Chromatographic Determination of Dissolved Gases from Transformer Insulating Oils”, 1994 Inter-national Symposium on Electrical Insulation, Pitts-burgh, PA, 1994.
3. IEEE C57.104-1991, “IEEE Guide for the Interpreta-tion of Gases Generated in Oil-Immersed Transform-ers”, 1991.
4. IEEE P1258, “IEEE Trial-Use Guide for the Inter-pretation of Gases Generated in Silicone-Immersed Transformers”, 1995.
5. Youngblood, Rick, et. al, “Application of DGA to De-tection of Hot Spots in Load Tap Changers”, Minutes of the Sixtieth Annual International Conference of Doble Clients, 1993, Sec. 6-4.
6. Charles Baker, Private Communication.
7. Stead, J. and Jakob, F., “Use of DGA to Confi rm Un-satisfactory Doble Test Results of 115 KV Bushings”, Minutes of the Sixty-third Annual International Con-ference of Doble Clients, 1996, Sec. 3-4.
8. Charles Baker, Private Communication.
Dr. Fredi Jakob received his PhD at Rutgers, the State University of New Jersey, in 1961. He is professor emeritus of analytical chemistry at California State University-Sacramento and is the founder and laboratory director of Analytical ChemTech International, Inc. (ACTI), which is a wholly owned subsidiary of Weidmann Systems International. As a long-term member of ASTM and IEEE and author of over fi fty published articles, Dr. Jakob is a traveling lecturer to private and governmental agencies. He has been invited to speak at American Public Power meet-ings, ASTM symposia, conferences held by Doble, NETA, and AVO conferences, as well as other industrial organizations.
Th e choices confronting insulating oil users have never been greater. Where conventional mineral oil has been the staple diet of transformers for over a hundred years, today’s technology and market demands have produced a variety of new fl uid options. Th is article discusses the new insulating fl uids on the market and describes how each can be used to solve specifi c problems.
It used to be easy....
Th e fi rst closed-core transformers were developed at the Abraham Ganz foundry in Budapest in 1884. Th ese origi-nal units were air cooled. Th e drawbacks of using air as a dielectric and cooling medium were soon apparent, and in 1890 the fi rst oil-cooled, oil-insulated transformer was build by Brown, GmbH, in Germany. Since that time, napthenic petroleum oil has been the standard cooling and insulating medium in liquid-fi lled transformers. Oils with a napthenic molecular structure were preferred over those with paraffi nic structure because they had better low temperature behavior and because napthenic oil was found in shallower wells, which made it easier to extract from the ground.
Th e specifi c petroleum fractions chosen for use in trans-formers were relatively light. Th is facilitated cooling fl ow inside the transformer and the use of transformers in cold environments.
Napthenic petroleum continues to be the standard for insulating oil used in the United States. In other parts of the world, scarcity of napthenic crude oil sources and improved dewaxing processes have shifted the markets to the use of paraffi nic oils, but the characteristics of the fi nal product are roughly the same.
But then we wanted fi re resistance…
In the early part of the 20th century, one of the
disad-vantages of using light petroleum fractions as insulating fl uids was their fl ammability. Th is was overcome with the
development of nonfl ammable, chlorinated fl uids. Taken together, these nonfl ammable fl uids are known as “askerals.” Th ese fl uids cooled and insulated well and allowed further use of transformers inside or near buildings because of their nonfl ammable character.
But there were also problems with these fl uids. Environ-mental studies showed that askarel fl uids were extremely persistent in the environment. In addition, studies showed that if the fl uids were exposed to an electric arc or ex-tremely high temperatures, highly toxic chemicals would be formed.
Th e use of askerals was phased out worldwide in the 1970s and 1980s. Several fi re-resistant fl uids were developed to take their place. Th e two main types of fi re resistant fl uids used in the US are fi re-resistant petroleum and silicone fl uid. An example of fi re resistant petroleum oil is shown in Table One.
Table One
Typical Characteristics of Fire Resistant Petroleum Oils
Characteristic & ASTM method Beta fl uid Transformer Oil
Fire Point, ASTM D92, Deg.C 306 145 Viscosity, D88, cSt. @ 100C 11.7 3.0
Density @ 20ºC, g/cc 0.87 0.87
Color, ASTM units L0.5 L0.5
Appearance Clear Clear
Dielectric Breakdown, D877 55 55
Dissipation Factor, 40ºC, D924, % 0.1 0.1 Acid Value, D664, mg KOH/g 0.01 0.01
New Insulating Oils:
Alternative to Transformer Oil
NETA World, Spring 2001
by David W. Sundin Kielectric Systems, Inc., Ph.D.
Insulating Oils Handbook
13
And now there are new choices….
With the development of fi re resistant fl uids, the cat was out of the bag. One size of transformer oil no longer fi t everyone. Transformer users recognized that diff erent characteristics of dielectric fl uids could solve specifi c prob-lems that they encountered, for example:
• Equipment operating at high temperatures
• Equipment operating in low ambient temperatures • Equipment situated in environmentally sensitive areas.
In the past decade, new insulating fl uids have been de-veloped to address each of these problems. Th ese fl uids are grouped together under the heading of “functional fl uids,” as their characteristics infl uence the performance of the equipment in which they are used. Functional fl uids will probably not replace the use of conventional transformer mineral oil, at lest in the foreseeable future, but they are proving themselves to be an important tool to help equip-ment makers achieve specifi c performance.
Highly biodegradable fl uids
Because of rising environmental liability and spill cleanup costs, power utilities have requested transformer and fl uid manufacturers to provide alternative dielectric fl uids that are more environmentally friendly than conventional transformer oil.
In response to these requests, fl uid manufacturers have developed several types of highly biodegradable fl uids. Some are made from synthetic hydrocarbons, some from vegetable oils, and some from synthetic chemicals called “esters.”
Most of these new fl uids biodegrade far more completely and rapidly than conventional transformer oil. For example, several of the “highly biodegradable” oils biodegrade more than 95 percent when tested with standard methods. In contrast, conventional transformer oil biodegrades to 30–50 percent when tested with the same methods.
Th e diff erent types of fl uids available vary widely in characteristics and price. Th is fi eld is still developing, and there have not been standards developed for fl uid character-istics, acceptable performance levels, or even test methods to determine minimum levels of biodegradability. To date, none of the fl uids has found suffi cient acceptance or use to become a standard for highly biodegradable fl uids.
One example of a highly biodegradable oil is ECO Fluid, which is made from synthetic hydrocarbon oils. Typical characteristics of ECO Fluid are shown in Table Two.
Table Two
Typical Characteristics of ECO Fluid
Characteristic & ASTM method ECO fl uid Transformer Oil
Biodegradation, CEC-L33 >95% ~30% Viscosity, D88, cSt. @ 100ºC 1.8 3.0
Density @ 20ºC, g/cc 0.85 0.87
Color, ASTM units L0.5 L0.5
Appearance Clear Clear
Dielectric Breakdown, D877 59 55
Dissipation Factor, 40ºC, D924, % 0.1 0.1 Acid Value, D664, mg KOH/g 0.01 0.01
Equipment at high temperatures
Specialty transformers are now being designed to operate with much higher heat rise than would have been accept-able a few years ago. Upgraded paper insulation systems can withstand hot spot temperatures that would have severely degraded old style Kraft insulation. Synthetic fl uids are available that resist oxidation and aging better than con-ventional mineral oil, and they have enhanced heat transfer characteristics. Using these fl uids in transformers that were built for mineral oil can yield temperature decreases of up to fi ve degrees centigrade with no additional cooling sur-face area. Because the synthetic oils are more stable than mineral oil, service life can be extended. In addition, these fl uids have a signifi cantly higher fi re point than conventional transformer oil, which provides a higher safety margin at these elevated operating temperatures. Th e characteristics of a fl uid made for high temperatures are shown in Table Th ree.
Table Three
Typical Characteristics of Alpha-2 Fluid
Characteristic & ASTM method Alpha-2
fl uid Transformer Oil
Fire Point, ASTM D92, Deg.C 250 145 Viscosity, D88, cSt. @ 40ºC 3.9 3.0
Density @ 20ºC, g/cc 0.82 0.87
Color, ASTM units L0.5 L0.5
Appearance Clear Clear
Dielectric Breakdown, D877 57 55
Dissipation Factor, 40ºC, D924, % 0.1 0.1 Acid Value, D664, mg KOH/g 0.01 0.01
Low ambient temperature applications
At temperatures below -45ºC, conventional transformer oils become too thick to eff ectively circulate in a transformer. Waxes in the oils form a crystalline structure, impeding oil fl ow in the cooling circuit. Without fl ow, hot spots can develop in the transformer’s core, even at the lowest ambi-ent temperatures. Th ese hot spots degrade insulating paper and signifi cantly shorten transformer life. Synthetic oils are now available that can remain fl uid down to -65ºC. Th is eff ectively prevents this problem and greatly extends the ambient temperature range in which transformers can be situated.
OptiCool fl uid is an example of an insulating oil made for use at very low temperatures. Blended from synthetic oils, it is stable at temperatures from -65º to 120ºC. OptiCool is miscible and compatible with conventional transformer oil. Th e Characteristics of OptiCool fl uid are compared with those of conventional transformer oil in Table Four.
Table Four
Typical Characteristics of OptiCool Fluid
Characteristic & ASTM method OptiCool
fl uid Transformer Oil
Pour Point, ASTM D97, ºC -65 -40
Viscosity, D88, cSt. @ 100C 1.7 3.0
Density @ 20ºC, g/cc 0.82 0.87
Color, ASTM units L0.5 L0.5
Appearance Clear Clear
Dielectric Breakdown, D877 59 55
Dissipation Factor, 40ºC, D924, % 0.1 0.1 Acid Value, D664, mg KOH/g 0.01 0.01
The next generation
Th e next generation of dielectric fl uids will almost cer-tainly follow the path outline here. Functional fl uids will be used to help equipment designers get the most out of their equipment. Some of the specialized applications that we can see on the horizon are:
• Supercooled devices will need distinct insulating fl uids that can be used at very low temperatures and with ma-terials compatible with cryogenic application.
• Th e proliferation of cogeneration equipment will re-quire new insulating oils that can be used with these devices.
Conclusions
We have looked at the trend in insulating oil develop-ment: the realization that dielectric fl uid characteristics can help achieve specifi c performance attributes in equipment. Some of the newer applications are in environmentally sen-sitive areas, in low ambient temperatures, and in equipment that operates at higher than normal temperatures.
New applications will continue to drive the develop-ment of improved functional fl uids. Th e next century will see changes in our industry that require highly specialized fl uids that will be used in equipment that we can only now imagine.
Dr. David Sundin is President of Dielectric Systems, Inc., a manu-facturer of fi re-resistant and other specialty dielectric materials. He is responsible for research and development on Dielectric System’s transformer insulating fl uids in addition to overseeing production and marketing activities. Prior to joining DSI he held engineering and man-agement positions at a major transformer manufacturer and was chief chemist at a large oil refi nery. Dr. Sundin is active in various industry standards committees. He holds a BA in chemistry, an MBA, and a PhD in Engineering. He is recognized expert in electrical insulating fl uids and fi re resistance in transformers; he has presented his research in profes-sional forums worldwide.
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TESTING SPECIFICATIONS F O R E L E C T R I C A L P O W E RInsulating materials used in power transformers have been selected because of their abundance, low cost, and longev-ity under normal operating conditions. Oils in the U.S. are expected to last 30 or more years before forming excessive amounts of acids and sludges and can then be rejuvenated by treatments with absorbents such as clay. Th ey can also be easily replaced. Modern oil preservation systems are designed to minimize exposure of the insulating oil to air thus retard-ing its oxidation. Th e solid insulation (paper and pressboard) is the main dielectric in transformers and also serves as mechanical support. Localized severe degradation in those materials must be considered most serious as this can result in loss of adequate dielectric strength. In addition, cellulosic materials cannot be easily replaced; therefore, their longev-ity, which is primarily a function of temperature, becomes a limiting factor in the operation of transformers. Th e end of life criteria, tensile strength, or degree of polymerization (DP) are physical characteristics of the paper insulation. If paper insulation is maintained in a dry state, its good elec-trical properties will be retained even as it becomes quite brittle. However, mechanically weakened paper can break especially as windings vibrate and move, particularly during through faults thus reducing insulating capability. Dielectric breakdown is then more likely to occur.
Fortunately, as cellulosic materials are degraded, byprod-ucts such as carbon oxide gases (carbon monoxide and carbon dioxide) and furanic compounds are formed which can serve as indicators of the aging process. Cellulosic materials, most often paper samples, can be tested directly for DP, a measure of its average molecular weight that correlates well with mechanical properties.
Cellulose is a long straight chain polymer (polysaccha-ride) of glucose molecules (monomers), and is the major constituent of paper and pressboard. Glucose is a sugar that has six carbons and is typically in the more stable ring structure called a pyranose. Th e glucose rings are linked by
an oxygen atom in what is referred to as a glycosidic link-age. Th e long-chain cellulose molecules interact with each other due to hydrogen bonding resulting in strands, mats and paper sheets.
Much of the mechanical strength of paper and pressboard comes from the long-chain cellulose polymer. As the cel-lulose ages, the polymers are cleaved and become shorter, resulting in reduced mechanical strength. Th e primary forms of degradation of the cellulose polymer are hydrolytic, oxida-tive, and thermal. In the case of each of these mechanisms free glucose is generated and the ring structure tends to be opened to form chains. Although temperature is likely to be the most important factor, oxygen and water have been clearly shown to have a signifi cant eff ect on the degradation of Kraft paper. Th e degradation of cellulose molecules results in the formation of gases, primarily carbon monoxide and carbon dioxide, furanic compounds, and other byproducts. Th e carbon oxide gases often provide early warning of excessive damage. However, other materials such as paints and gaskets can outgas carbon oxide gases when exposed to excessive temperatures and, therefore, are not always attributable to the degradation of the cellulosic insulation. Confi rmatory and complementary tests have been developed which detect oil soluble breakdown products of the cellulose chain (called furanic compounds) with the primary indica-tor being 2-furfural.
Furanic Compounds
Furanic compounds are fi ve-membered ring structures that are formed in a manner in which the open-chain glu-cose molecule goes through a series of dehydration reactions (elimination of water molecules) and then recycles into a fi ve-membered ring structure. Th e furanic compounds, unlike sugars such as glucose, are oil soluble and, therefore, are detectable.
Using Analytical Techniques
to Determine Cellulosic Degradation
in Transformers
NETA World, Winter 2001-2002
by Lance R. Lewand Doble Engineering Company
