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Insulating Oils Handbook 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

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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 Lance R. Lewand

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation, or warranty as to any opinion, product, or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser, or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct, or indirect damages. NETA further disclaims any and all warranties, express or implied including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date. Copyright © 2009 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

1

Insulating Oils Handbook

Continuous Moisture-in-Oil Sensing: Field Applications for the Power Industry PowerTest 2000 (NETA Annual Technical Conference) Presenters Lance R. Lewand and Paul J. Griffin Doble Engineering Company

This paper discusses the application of a continuous moisture-in-oil sensor that operates in dielectric fluids, such as transformer mineral oils. The sensor can be used to help in the assessment of the condition of transformers and for oil processing.

Introduction The principal reason for developing a continuous moisture-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 affects 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. The dielectric breakdown strength of the paper insulation decreases substantially when its water content rises above 2 to 3 % by weight. The dielectric breakdown voltage of the oil is affected by the relative saturation (RS) of water in oil which is constantly changing in a transformer environment. The 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 (100%

22°C

30

50%

About half of high 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. That is, it remains a function of the relative saturation 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. The relative saturation of water remaining in the oil will influence its dielectric breakdown voltage. For this reason continuous measurement can be used to detect conditions in which moisture distribution is a problem.

Determination of the amount of water removed by filtering and/or dehydrating processes

Determination of the effectiveness of field-drying a transformer

Determining the proper time to change filter cartridges due to filter bleed-through is a concern during transformer oil processing. Changing them is usually based on differential pressure or a pressure increase, which can result from excessive moisture, or particulate contamination. This is often late in the process, when high amounts of dissolved water is already in the processed oil. The 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 filters should be changed, and therefore speeding up the drying process. In most cases, a moisture-in-oil sensor would indicate the need for a filter 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 filter is most effective, and then starts to increase gradually. A reasonable end point can be chosen to change the filter before it becomes ineffective. Monitoring of the differential pressure is still a valuable practice as filters can be plugged from particulate contamination and free water. One of the most beneficial 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 titration measurements (and the associated chemicals and their

5

Insulating Oils Handbook disposal). The algorithm used in this particular moisturein-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. 60

Water Content, ppm

50

appropriate actions can be taken to improve it. The moisturein-oil sensor can be used in a similar fashion to determine the best operating conditions for the use of filters. Calculating the total amount of water removed can be a useful measure of dehydrating effectiveness. It is quite simple for oil in a storage tank. For instance, using Equation 3, it can be determined that a filtering or dehydrating process which removes 35 ppm of water (difference between inlet and outlet measurements) on 10,000 gallons of oil would remove 1.2 liters of water. (Equation 3)

40

30

20

10

0

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

Karl Fischer Titration

Figure 8 — Moisture-In-Oil Sensor Versus Karl Fischer Titration

The accuracy of this particular sensor in ppm varies with the temperature of the measurement because it is a conversion 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, PPM

10°C

± 1%

± 0.40

0°C

20°C

40°C

60°C

80°C

± 1%

± 1%

± 1%

± 1%

± 1%

Where: Wt = The total amount of water removed in liters Voil = The volume of oil in gallons Ci = The inlet concentration of water in oil in ppm wt./wt. from the moisture-in-oil sensor Co = The 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:

Samples DOMINO

Wt = 3.31X 10-6 Voil (Ci –Co)

± 0.25

± 0.60

± 1.25

± 2.50

± 4.50

The moisture-in-oil sensor can be used to estimate the efficiency of an oil dehydrating process using vacuum or filters. In the case of vacuum dehydrating, the inlet and outlet oil can be monitored to determine the best flow rate, dwell time, applied vacuum, temperature, and if other mechanical aspects of the process are functioning adequately. This can be done by comparing the difference in the water content of the oil at the inlet and outlet of the processor. The greatest difference in water contents will indicate optimum efficiency. Once the most efficient processing conditions have been set, the moisture-in-oil sensor can then be used to continuously monitor the process. If the efficiency begins to decline, then

Wt = 3.31X 10-6(10,000gallons)(40–5)=1.2 liters of water The effectiveness of field drying of the transformer, whether the process is conducted out of service or in-service, is much more difficult to assess than drying the oil alone. This 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: The oil contains about 1.0 liter of water The paper contains about 78.5 liters of water The entire system would have an estimated total volume of approximately 80 liters The amount of water in oil was determined by Equation 3, where: Ci = the water-in-oil content Co = 0

6

Insulating Oils Handbook

The amount of water in the paper is estimated by multiplying 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 The amount of water in the paper can be calculated by two means, using an equation or a family of curves. The equation is as follows: (Equation 4) Cp = {2.17x10-5x[(RStox10-2)(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 = The saturation vapor pressure at temperature, Tto (from published data, see Reference 8). The 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 The 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). This mass can then be easily converted to liters of water by multiplying by 0.454 liters/pound for a volume of 78.5 liters. The 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 find the equilibrium value [4]. Once the drying process has been completed the same estimation process for moisture in the cellulosic materials can be repeated. This should be done after the transformer has been at an elevated temperature for at least three days without processing. The difference in the amount of water before and after filtering is the quantity removed. Another way to determine how much water is removed by processing each day is to use Equation 3. The flow 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 significantly then the calculation should be restarted and the volumes of water removed summed for each set of calculations. The efficiency of the process can readily be observed by examining the difference 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 final concentration of 0.5% or lower. This 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. The measurement of the capacitance of a thin-film polymer is used to detect the relative saturation (RS) of water in oil. The relative saturation 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 filter bleed-through

An alternative to taking oil samples for water content by chemical analysis Determination of oil processing efficiency

Determination of the amount of water removed by filtering and/or dehydrating processes

Determination of the effectiveness of field-drying a transformer

References [1] Griffin, P. J. “Water in Transformers – So What!”, National Grid Condition Monitoring Conference, May 1996. [2] Lewand, L. R. and Griffin, P. J., “How to Reduce the Rate of Aging of Transformer Insulation”, NETA World, Spring 1995, pp. 6-11. [3] Lewand, L. R. and Griffin, P. J., “Transformer Case Studies”, Proceedings of the Sixty-Six Annual International Conference of Doble Clients, 1999, Sec.5-7.

[4] Griffin, P. J. “How to Prevent Rain in Power Transformers”, ASTM Standardization News, November 1991, ASTM, Philadelphia, PA, pp. 30-33.

[5] Griffin, P. J., Bruce, C. M., and Christie, J. D. “Comparison of Water Equilibrium in Silicone and Mineral Oil Transformers”, Minutes of the Fifty-Fifth Annual International Conference of Doble Clients, 1988, Sec. 10-9.1. [6] “Estimating the Water Content of Cellulosic Insulation”, MKT-AB-12, Rev A, Doble Engineering Company DOMINOTM Application Bulletin, November, 1999, 4 pp.

[7] “Transformer Oil Field Processing Applications”, MKT-AB-16, Rev A, Doble Engineering Company DOMINOTM Application Bulletin, November, 1999, 6 pp.

Insulating Oils Handbook [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. Griffin received his BS degree at the American International College and his MS at the University of Rhode Island. He has been employed 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.

7

8

Insulating Oils Handbook

Dissolved Gas Analysis — Past, Present and Future PowerTest 2000 (NETA Annual Technical Conference) Fredi Jakob, Ph.D. Analytical ChemTech International, Inc.

I. Introduction It has been well over thirty years since dissolved gas analysis, DGA, was introduced as a diagnostic tool for monitoring mineral oil filled transformers. It is now universally accepted as the method of choice to locate incipient thermal and electrical faults. DGA methodology and applicability have evolved significantly since its inception. The evolutionary development includes new laboratory methods, on-line DGA, application to additional types of fluid filled equipment, application to dielectric fluids 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 monitor one or more gas in oil concentrations, are available for on-line analysis. DGA was originally developed for transformers, but it is now being applied to load tap changers, oil filled circuit breakers, oil filled bushings and cable oil. Data interpretation methods have been extensively developed for transformers filled with mineral oil and IEEE is currently developing a guide for silicone fluid filled transformers.

II. Laboratory Methods ASTM procedure, D 36121, provides two different methods for the extraction of dissolved gases from dielectric fluid. Method D 3612-A involves an extraction process that precedes the subsequent gas analysis. The dielectric fluid is delivered into a previously evacuated glass apparatus and is stirred for a sufficient time to extract most of the dissolved gases. The volume of the evacuated glassware must be large in comparison to the volume of dielectric fluid so that most of the dissolved gases leave the fluid phase. The evolved gas is compressed and the volume and temperature are measured. Then, one or more aliquots of the gas are separated and quantified with a gas chromatograph. Each gas concentration 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. The advantages of this method are speed and elimination of potential mercury health hazards. One disadvantage is that method B cannot be used with Silicone fluids 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. The ASTM document states, “The limit of detection for hydrogen specified in Method B is higher than that specified for Method A. This could effect 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 vol1 Gases

Method D 3612-A

Method D 3612-B

Hydrocarbons

1

1

Hydrogen

Carbon Oxides

5

25

Atmospheric Gases 50

20

2

500

New DGA methodology that involves a two stage process2 has been developed and is being reviewed by ASTM committee D-27 (Proposed Designation D 3612-C). The first 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 coefficients are used to correlate gas

9

Insulating Oils Handbook concentrations in the headspace of the sample container with the initial gas concentrations in the oil. The second stage involves analysis of the evolved gases with a gas chromatograph. The 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 coefficients with oil type, though most believe the difference of results due to this factor is not significant.

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 effectively monitored on an ongoing basis. Since DGA is accepted as an excellent diagnostic monitoring tool a great deal of effort has been expended to develop on-line DGA. The 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. The small mobile hydrogen atoms, and to a lesser extent other small molecules such as CO, are most readily separated. The 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 fitted 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. This multiple stage extraction procedure is potentially more effective than a single stage extraction such as that used in ASTM D 3612-A . The extracted gases can then be separated and analyzed by gas chromatography or quantified 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 sufficiently viable compromise.

IV. Applicability of DGA A. Fluid Types Thermal or electrical faults release energy that will result in the partial molecular destruction of dielectric fluids. The extent of the molecular rearrangement depends on the available energy and the nature of the dielectric fluid. Faults

will produce gases in mineral oils, high molecular weight hydrocarbons, PCB’s, silicone fluids, perchlorethylene and other dielectric fluids. Since DGA interpretation is empirical in nature it has only been effectively applied to dielectric fluids that have been extensively studied. The current IEEE guide3, 57.104, covers the application of DGA to mineral oils only. High molecular weight hydrocarbons, also known as less flammable hydrocarbons, contain similar molecules to those present in conventional mineral oil and produce the same gases under similar fault conditions. The IEEE guide is applicable, without modification, for these fluids. Silicone fluids produce the same fault gases as mineral oils when they are thermally or electrically stressed, but relative concentrations and fault gas concentration ratios are different. A separate IEEE trial-use guide, P1258, has been developed for these fluids4. IEEE guides for the other fluids are not currently available.

B. Equipment Types DGA was initially developed to monitor transformers and the success of this method is well known. Fault conditions can exist in any type of electrical equipment and if this equipment contains dielectric fluids, fault gases will be produced. Table 2 shows the correlation between fault types and the various fault gases.

Table 2 Fault Gases Gases

Indication

Methane, Ethane, Ethylene

“Hot Metal” gases

Carbon Oxides

Cellulose insulation degradation

Hydrogen Acetylene

Partial discharge, heating, arcing

Arcing

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 common 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, followed by additional carbon build up on the contacts. This process leads to exponentially increased heating or “thermal runaway” and carbon build up. Youngblood 5 was one of the first investigators to realize that the coking problem would result in the production of the “hot metal gases,” methane, ethane and especially ethylene. The concentration of these gases depends on a number of variables including breathing type, manufacturer, model type, etc. Generic fault gas threshold values, similar to those in the IEEE guide for transformers, have been developed by Youngblood and are given in Table 3.

10

Insulating Oils Handbook Table 3

2. Oil Filled Bushings

LTC Monthly Watch Criteria LTC Type

Hydrogen

>1500 ppm

>1000 ppm

>1000 ppm

Sealed

>5000 ppm

>9000 ppm

>1200 ppm

Free or Desiccant Breather Vacuum

Acetylene

5

>10 ppm

>5 ppm

Ethylene

> 100 ppm

John Stead presented a paper at the 1996 Doble conference7 showing how DGA could resolve conflicting Power Factor results for two bushings from the same manufacturer. The DGA data for these two bushings is given in Table 5. This data clearly indicates that partial discharge is occurring in bushing 2. The low ratio of CO2 / CO indicates severe overheating of the paper in the bushing. Physical inspection confirmed the interpretation of the DGA results.

Charles Baker6 and others have developed manufacturer specific flag points and this approach, which is illustrated in Table 4, is probably the most promising.

Table 4

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

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

This unit was determined to be operating properly. The low concentrations of hydrogen and acetylene are considered normal for a free breathing unit. The unit was scheduled for annual testing. Date: February 25, 1994 Date

Mfr. Serial Number C2H2 CH4

02/25/94 AC 018226580301 44

CO CO2

3143 149 33

645

This unit was in “thermal runaway” when tested. Notice the high level of ethylene, which is the key gas for overheating. This unit was already heavily coked when the DGA test was conducted. The unit was removed from service and repaired. The 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

Nitrogen

Bushing 1 1705

5546

146

1256

1.8

11

95%

Density @ 20ºC, g/cc

0.85

Viscosity, D88, cSt. @ 100ºC Color, ASTM units

Transformer Oil ~30%

1.8

3.0

0.87

L0.5

Appearance

Dielectric Breakdown, D877

Dissipation Factor, 40ºC, D924, % Acid Value, D664, mg KOH/g

L0.5

Clear

Clear

0.1

0.1

59

55

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 acceptable a few years ago. Upgraded paper insulation systems can withstand hot spot temperatures that would have severely degraded old style Kraft insulation. Synthetic fluids are available that resist oxidation and aging better than conventional mineral oil, and they have enhanced heat transfer characteristics. Using these fluids in transformers that were built for mineral oil can yield temperature decreases of up to five degrees centigrade with no additional cooling surface area. Because the synthetic oils are more stable than mineral oil, service life can be extended. In addition, these fluids have a significantly higher fire point than conventional transformer oil, which provides a higher safety margin at these elevated operating temperatures. The characteristics of a fluid made for high temperatures are shown in Table Three.

Table Three

Typical Characteristics of Alpha-2 Fluid Characteristic & ASTM method Fire Point, ASTM D92, Deg.C Viscosity, D88, cSt. @ 40ºC Density @ 20ºC, g/cc Color, ASTM units Appearance

Dielectric Breakdown, D877

Dissipation Factor, 40ºC, D924, % Acid Value, D664, mg KOH/g

Alpha-2 fluid 250 3.9

0.82

L0.5

Transformer Oil 145 3.0

0.87

L0.5

Clear

Clear

0.1

0.1

57

0.01

55

0.01

14

Insulating Oils Handbook

Low ambient temperature applications

Conclusions

At temperatures below -45ºC, conventional transformer oils become too thick to effectively circulate in a transformer. Waxes in the oils form a crystalline structure, impeding oil flow in the cooling circuit. Without flow, hot spots can develop in the transformer’s core, even at the lowest ambient temperatures. These hot spots degrade insulating paper and significantly shorten transformer life. Synthetic oils are now available that can remain fluid down to -65ºC. This effectively prevents this problem and greatly extends the ambient temperature range in which transformers can be situated. OptiCool fluid 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. The Characteristics of OptiCool fluid are compared with those of conventional transformer oil in Table Four.

We have looked at the trend in insulating oil development: the realization that dielectric fluid characteristics can help achieve specific performance attributes in equipment. Some of the newer applications are in environmentally sensitive areas, in low ambient temperatures, and in equipment that operates at higher than normal temperatures. New applications will continue to drive the development of improved functional fluids. The next century will see changes in our industry that require highly specialized fluids that will be used in equipment that we can only now imagine.

Table Four

Typical Characteristics of OptiCool Fluid Characteristic & ASTM method Pour Point, ASTM D97, ºC Viscosity, D88, cSt. @ 100C Density @ 20ºC, g/cc Color, ASTM units Appearance

Dielectric Breakdown, D877

Dissipation Factor, 40ºC, D924, % Acid Value, D664, mg KOH/g

OptiCool fluid

Transformer Oil

1.7

3.0

-65

0.82

L0.5

Clear 59

0.1

0.01

-40

0.87

L0.5

Clear 55

0.1

0.01

The next generation The next generation of dielectric fluids will almost certainly follow the path outline here. Functional fluids 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 fluids that can be used at very low temperatures and with materials compatible with cryogenic application. • The proliferation of cogeneration equipment will require new insulating oils that can be used with these devices.

Dr. David Sundin is President of Dielectric Systems, Inc., a manufacturer of fire-resistant and other specialty dielectric materials. He is responsible for research and development on Dielectric System’s transformer insulating fluids in addition to overseeing production and marketing activities. Prior to joining DSI he held engineering and management positions at a major transformer manufacturer and was chief chemist at a large oil refinery. 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 fluids and fire resistance in transformers; he has presented his research in professional forums worldwide.

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15

Insulating Oils Handbook

Using Analytical Techniques to Determine Cellulosic Degradation in Transformers NETA World, Winter 2001-2002 by Lance R. Lewand Doble Engineering Company

Insulating materials used in power transformers have been selected because of their abundance, low cost, and longevity 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. They can also be easily replaced. Modern oil preservation systems are designed to minimize exposure of the insulating oil to air thus retarding its oxidation. The 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 longevity, which is primarily a function of temperature, becomes a limiting factor in the operation of transformers. The 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 electrical 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, byproducts 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 (polysaccharide) 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. The glucose rings are linked by

an oxygen atom in what is referred to as a glycosidic linkage. The 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 cellulose ages, the polymers are cleaved and become shorter, resulting in reduced mechanical strength. The primary forms of degradation of the cellulose polymer are hydrolytic, oxidative, 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 significant effect on the degradation of Kraft paper. The degradation of cellulose molecules results in the formation of gases, primarily carbon monoxide and carbon dioxide, furanic compounds, and other byproducts. The 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. Confirmatory and complementary tests have been developed which detect oil soluble breakdown products of the cellulose chain (called furanic compounds) with the primary indicator being 2-furfural.

Furanic Compounds Furanic compounds are five-membered ring structures that are formed in a manner in which the open-chain glucose molecule goes through a series of dehydration reactions (elimination of water molecules) and then recycles into a five-membered ring structure. The furanic compounds, unlike sugars such as glucose, are oil soluble and, therefore, are detectable.

16 High concentration of 2-furfural is a clear indication of cellulose degradation as this is the only type of material in transformers which yields this byproduct. Under some conditions where carbon oxides may be lost, such as when a leak occurs in the gas space of a nitrogen blanketed transformer or from the conservator tank for those that are free breathing, the furanic compounds will continue to accumulate and provide a gross indication of the relative aging of the cellulosic insulation or a thermal incipient-fault condition involving cellulosic materials. Conversely, when cellulosic materials are exposed to extreme temperatures which result in charring, furanic compounds can be destroyed and the carbon oxides may be the only byproducts remaining in significant quantities. Experience is required in evaluating the furanic compound data since there are factors such as the type of insulation preservation/oil expansion system, type of conductorwrapped insulation, and family of transformer, all of which influence the interpretation. For example, the treatment of the oil or the transformer can result in the removal of significant amounts of furanic compounds. Not knowing this information may lead to a misdiagnosis of the actual condition of the transformer. In addition, furanic compounds are generated from thermal events, not electrical discharge activity and therefore can be useful in the assessment of failure mode and incipient-fault conditions leading to the failure. Tests for furanic compounds should be performed initially for all power transformers to establish a baseline, for important or older transformers, when high carbon oxides are generated, for highly loaded transformers, and when other tests indicate accelerated aging. In order to detect the degradation of cellulosic materials, sufficient quantities must be degraded to increase the concentration of indicator gases and furanic compounds in the oil to thresholds considered to be problematic. Experience has shown that significant damage, including charring of the cellulosic insulation, when limited to isolated hot spots due to incipient-fault conditions, will produce carbon oxides and furanic compounds below thresholds used to indicate problems involving the cellulosic insulation. The analysis of data for furanic compounds should be based on the type of insulating paper used and the preservation system employed. For Kraft paper insulation, suitable guidelines are as follows: • For normal aging 50 ug/L/year of 2-furfural is considered accelerated aging

• Values of 2-furfural > 1000ug/L should raise a flag for further study For thermally-upgraded (TU) Kraft paper insulation using the dicyandiamide process, practical guidelines are as follows:

Insulating Oils Handbook • For normal aging the rate of 2-furfural generation should be much less than 50 ug/L/year and usually in the vicinity of 10-20 ug/L/year

• If estimating insulation quality from the 2-furfural content, use these guidelines: • Normal

• Midlife (examine rate) • Last third of life?

100 1000 ug/L (flag for further study)

Degree of Polymerization (DP) The degree of polymerization test is used to assess insulation aging and is performed on paper samples taken directly from the transformer so it is an intrusive test. The DP provides an estimate of the average polymer size of the cellulose molecules in materials such as paper and pressboard. The DP correlates well with mechanical properties such as tensile strength but has the advantage that it can be performed on used materials that have taken a set during service life. Generally, paper in new transformers has a DP of about 1000. Aged paper with a DP of 150-200 has little remaining mechanical strength, therefore making the windings more susceptible to mechanical damage during physical movement, which can cause the paper to tear or crumble. This may occur when transformers are moved or during events such as through faults. Since paper insulation does not age uniformly due to thermal, water, oxygen and byproduct concentration gradients, samples from several distinct locations provide the best diagnosis. The DP test provides the most reliable indication of the overall aging of the paper insulation as it is a direct measurement. This test should be performed: • when there is other evidence of very accelerated aging of the insulation • when an internal investigation is being performed and the transformer is more than 20 years old

• for condition assessment of older transformers for possible refurbishment • for consideration of a partial rewind • for failure assessment

• for condition assessment of insulation when purchasing a service-aged transformer • to assess the condition of a transformer after an extreme overheating event such as loss of cooling

Insulating Oils Handbook Conclusions The combination of analyses of furanic compounds in oil, DP, along with routine dissolved gas-in-oil analysis is a very powerful set of tools to assess the condition of the cellulosic insulation. The more specific information known about a transformer and its family, the better the diagnosis that can be provided. Lance Lewand received his BS degree at St. Mary’s College of Maryland in 1980. He has been employed by the Doble Engineering Company for the past seven years and is currently Project Manager of Research in the materials laboratory and Product Manager for the DOMINOTM product line. Prior to his present position at Doble, he was the 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.

17

18

Insulating Oils Handbook

Understanding Water in Transformer Systems The Relationship Between Relative Saturation and Parts per Million (ppm) NETA World, Spring 2002 by Lance R. Lewand Doble Engineering Company

Water content in transformer oil in parts per million (ppm) is a familiar concept to most in our industry, and limits of 30 to 35 ppm are generally referenced. However, these simple concentration limits have limited value in diagnosing the condition of transformer systems and, thus, the concept of relative saturation (RS) of water in transformer oil has been re-introduced over the past 15 years. The concept of relative saturation of water in transformer oil is not a new one and was originally championed by Frank Doble as early as the mid 1940s.Thus, this article discusses and details the relationship between RS and ppm. It is well known that moisture continues to be a major cause of problems in transformers and a limitation to their operation. Particularly problematic is excessive moisture in transformer systems, as it effects both solid and liquid insulation with the water in each being interrelated. Water affects the dielectric breakdown strength of the insulation, the temperature at which water vapor bubbles are formed, and the aging rate of the insulating materials. In the extreme case, transformers can fail because of excessive water in the insulation. The dielectric breakdown strength of the paper insulation decreases substantially when its water content rises above two to three percent by weight. Similarly, the dielectric breakdown voltage of the oil is also affected by the relative saturation (RS) of water in oil. The 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 (69 kV 288 kV Units

Perform on >288 kV Units

Color

D 1500

YES

YES

YES

Dielectric Breakdown Voltage

D 877

YES

YES

NO

Dielectric Breakdown Voltage

D 1816

YES

YES

YES

Dissolved Gases in Oil

D 3612

YES

YES

YES

Furanic Compounds in Oil

D 5837

YES

YES

YES

Interfacial Tension

D 971

YES

YES

YES

Neutralization Number

D 974

YES

YES

YES

Oxidation Inhibitor Content

D 2668

YES

YES

YES

Particle Count

Doble

NO

YES/NO

YES

Pour Point

D 97

NO

YES/NO

YES

Power Factor at 25°C

D 924

YES

YES

YES

Power Factor at 100°C

D 924

YES/NO

YES

YES

Relative Density 60/60

D 1298

YES

YES

YES

Viscosity at 40°C

D 445

NO

YES/NO

YES

Visual Examination

D 1524

YES

YES

YES

Water Content and % Saturation

D 1533

YES

YES

YES

YES/NO indicates that it is a useful test to perform but it is not always necessary. It has become common practice to group some of the tests listed in Table 6 into “screen packages” consisting of five to 10 tests which are routinely employed to check the condition of transformer oil. For example, physical tests such as visual examination/color and relative density are combined with electrical tests such as dielectric strength and power factor and also with chemical tests such as water content and neutralization number to form a screen package. Be advised that each laboratory has its own screen package tests and there is no standardization throughout the industry. Make sure the screen package that a laboratory is offering are the tests that are required. Lance Lewand received his BS degree at St. Mary’s College of Maryland in 1980. He has been employed by the Doble Engineering Company for the past ten years and is currently Project Manager of Research in the materials laboratory and Product Manager for the DOMINOTM product line. Prior to his present position at Doble, he was the 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.

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26

Insulating Oils Handbook

Choosing a Sample Container for Transformer Oil Analysis NETA World, Fall 2002 by Lance R. Lewand Doble Engineering Company

The last several articles discussed understanding water in transformer systems and which tests to choose and when. The results obtained from the analysis of a sample can provide unparalleled information concerning the condition of the insulating materials within electrical apparatus, life assessment, and the operating condition of the device. However, a sample that is not representative of the bulk oil insulation can provide erroneous information that can easily mislead personnel to incorrectly assess the condition of the oil or the electrical apparatus. The art of sampling is very important and will be covered in a future article. One aspect of the sampling function that is often overlooked is the sample container itself. Unfortunately, there are many instances in which the sample container plays a major role in the quality of the sample taken.

Purpose of a Sample Container Sample containers are used to retrieve and store samples. It is important for them to prevent contamination and to provide the best sample for a specific test. ASTM Practices D 923 and D 3613, the Doble Reference Book on Insulating Liquids and Gases, or IEC Methods and Guides 60475 and 60567 are to be consulted when choosing a sample container. Sample containers should have the following characteristics. They must: • Be large enough to hold the volume of liquid necessary for analysis.

• Not impart any contamination (chemicals or particles) to the sample from the container itself. • Seal the sample from external contamination.

• Shield the sample from direct sunlight to prevent photodegradation. This can be done either by having a dark container or by having a covering for that container.

• Prevent the loss or gain of gases or water when testing for these properties. The volume of the sample is of the utmost importance, as various analytical tests require very different sample volumes. For example, a test for inhibitor content (ASTM D 2668) requires only a few milliliters of oil whereas the test for impulse breakdown (ASTM D 3300) may require as much as two to four liters. In general, it is good practice to provide the sample volume required for each test plus ten percent. If unsure of the sample volume required for specific test or tests, laboratories such as the Doble Materials Laboratory have reference lists that detail such information.

Which Sample Container to Use For general oil quality tests, glass bottles — either amber or clear — function well. Amber bottles provide protection against photodegradation while clear bottles enable visual inspection of the sample. To prevent photodegradation in clear bottles, shielding from direct sunlight by storing them in cardboard or some other type of container works well. Bottle caps must be constructed from a compatible material that will not contaminate the sample. For example, bottle caps with liners composed of paper or having glue that is soluble in the oil are not appropriate. Liners made out of foil, Teflon® or polyethylene are usually safe to use. If sealed tightly, the glass bottle is an appropriate container from which to draw a sample for water analysis. However, problems have been encountered with caps working loose over time. If not properly protected, glass bottles are more apt to break than other containers, and they are not suitable containers for dissolved gas-in-oil analysis, as gases such as hydrogen and carbon monoxide will be lost. Metal cans have become popular because they are more resistant to breakage than glass bottles. Cans with soldered seams prepared with some fluxes will contaminate the sample; therefore, welded seams are preferred. Cans made

27

Insulating Oils Handbook of tin, aluminum, and stainless steel have been used and are especially good containers to hold samples for oil quality tests. Metal bulbs constructed out of stainless steel are also used and can be invaluable when sampling in areas that have a lot of airborne environmental contamination such as coastal areas where salt spray is common. The use of plastic bottles has grown significantly in the past decade. Like cans, they resist breakage and shield the sample from sunlight when dark plastics are used. They are appropriate containers for samples in which oil quality tests are to be performed. Samples being tested for water should not be stored in plastic bottles as water ingress or egress can occur in just a few hours. Not all plastics are compatible with oil so selection of the construction material is important, and containers made of substances such as polypropylene, polyvinyl chloride (PVC), and especially polystyrene are not appropriate. Tests such as power factor will be affected by incompatible plastic bottles because of dissolved components transferred to the sample that will cause increases in dielectric loss. Bottles made of high density polyethylene have been found suitable and are one of the preferred sample containers when electrostatic charging tendency or furanic compound analysis is to be performed. In the case of furanic compounds, high-density polyethylene does not have the silanol groups found in glass that attracts the semipolar furanic compounds to the glass walls and thus removes them from the sample. Samples with a low concentration of furanic compounds are not as affected as samples with larger amounts of furanic compounds. The most appropriate container for taking samples for dissolved gas-in-oil and water content analyses, and the easiest to manipulate, is the ground glass syringe whose barrel and plunger have extremely tight tolerances. This type of syringe has been found to satisfactorily prevent the ingress of gases and water into the sample, and in turn prevent the egress of water and dissolved gases from the sample over a period of time. Care should be taken with glass syringes to ensure the stopcock is tight and in the closed position once the sample is taken. Also, the samples collected in syringes must be quickly protected from photodegradation (degradation by light) by immediately placing them in the dark or in their shielding containers. Stainless steel cylinders may also be used but can be more difficult to manipulate or to determine when all the air has been removed from the cylinder. Metal cylinders will also add significant shipping costs because of weight but are definitely more durable in transit. Sample identification is an extremely vital aspect of the sampling process, and the identification is usually attached to the container itself to avoid confusion. Many laboratories receive samples that can not be related to a specific device. Even if the sample was taken correctly, the lack of proper identification makes the sample useless, and is therefore a bad sample. When sampling personnel retrieve samples from electrical apparatus, it should be done in a prescribed sequence so nothing is forgotten.

Sample Storage and Transport Samples should not be stored longer then a few days before shipping to the laboratory for analysis. The properties of the dielectric liquid tend to decay over time, and gases for dissolved gas analysis (DGA) can be lost or gained if the sample is held too long, as there is a finite time in which the sample container can maintain the sample integrity. Remember that the sample is supposed to represent the bulk liquid insulation and storing it too long will change those properties. Store samples in the dark to prevent photodegradation, and keep them away from temperature extremes and humid environments. Package the sample containers to protect from leakage and breakage, especially if the samples are in glass. The United States Environmental Protection Agency Resource Conservation and Recovery Act (RCRA) listed in 40 CFR Part 261.4(d) requires that all samples shipped must be packaged so they do not leak, spill, or vaporize from their packaging. Other countries may have similar requirements as well. Use methods to prevent sample container breakage or leakage such as the use of cardboard, Styrofoam, and other protective materials. Package the samples in such a way as to avoid container-to-container contact. Also, some shipments become too heavy and unwieldy, and the shipping company may not be able to handle it safely. In this case, it is advisable to separate the shipment into several packages. Lance Lewand received his BS degree at St. Mary’s College of Maryland in 1980. He has been employed by the Doble Engineering Company for the past seven years and is currently Project Manager of Research in the materials laboratory and Product Manager for the DOMINOTM product line. Prior to his present position at Doble, he was the 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.

28

Insulating Oils Handbook

OCB Diagnostics PowerTest 2002 (NETA Annual Technical Conference) Presenter Fredi Jakob, Ph.D., Weidmann-ACTI Co-Authors Karl Jakob, P.E., and Simon Jones, Weidmann-ACTI Rick Youngblood, Cinergy Alex Salinas, Southern California Edison

I. Introduction

III. Diagnostics

During the B.D. era, before deregulation, run to failure, time based and operation count based maintenance methods were widely employed. These methods were effective in maintaining the power delivery system but were labor intensive and not cost effective. Time based and operation count based maintenance methods could not identify units that developed problems between scheduled inspections. Units were often inspected on a time basis and no problems were identified. After deregulation, A.D., fiscal requirements led to decreases in trained maintenance personnel, deferral of capital expenditures, equipment life extension programs, and efforts to maximize uptime and minimize maintenance costs. Reliability centered and condition based maintenance are key A.D. concepts that have been implemented in the power industry. The ultimate goal of condition based maintenance would be to perform maintenance “just in time”, before the equipment fails in service. Condition based maintenance requires periodic or continuous (online) equipment monitoring. Equipment is scheduled for inspection and/or maintenance only when diagnostic test results indicate a potential problem.

Development of our diagnostic program involved four sequential steps: 1) Identification of fault mechanisms 2) Selection of appropriate physical and chemical tests to detect problem units 3) Correlation of test data with physical inspection of problem units and 4) Development of algorithms to classify OCB condition.

A. Fault Types OCB contacts can become coated with oxides or sulfides, which result in increased contact resistance and increased contact operating temperatures. Contacts also erode because of mechanical wear or arcing. Arc suppression grids, which are made of cellulose, deteriorate to some degree whenever an arc is suppressed. Each of these OCB problems can be detected with one or more diagnostic tests. Figures 1 shows contacts that have been severely eroded. Figure 2 illustrates a new arc suppression grid and one that shows degradation. A wide range of chemical and physical test methods is available to detect these types of faults.

II. OCB Maintenance Oil filled circuit breakers; OCB’s have traditionally been serviced on a time based, operational count or fault current basis. We believe that OCB condition can be ascertained by non-invasive diagnostic tests that can reliably indicate when an internal inspection and/or maintenance or repair is required. Cinergy, Southern California Edison and Weidmann-ACTI have cooperated in a project to identify a battery of chemical and physical tests to assess OCB condition.

Figure 1

Insulating Oils Handbook

“Good” Grid

Close up of a Degraded Grid. Figure 2

B. Laboratory Tests Dissolved Gas Analysis, DGA, has been extensively applied to locate incipient thermal or electrical faults in transformers. Normal OCB operation will produce the “key gases” associated with arcing under oil. These key gases include acetylene and hydrogen, which are produced at the very high temperatures associated with arcing. The “hot metal gases”, methane, ethane and ethylene are produced whenever the oil is overheated from any cause. The temperature required to produce acetylene is considerably higher than that required to produce the hot metal gases. Insulating fluids absorb and distribute fault energy. Thus the temperature of the oil is very high in the vicinity of an arc and decreases with distance away from the arc. This variation of temperature results in the production of acetylene close to the arc and hot metal gases further removed from the arc location. Very little heating occurs in a healthy OCB so the amount of hot metal gases generated should be small. This analysis of key gas production mechanisms

29 indicates that the ratio of heating to arcing gases should be indicative of problems such as increased contact resistance or contact erosion. Arc suppression grids deteriorate every time that they quench an arc. When the grids are new the arc suppression time is low. The particles generated from the grid degradation are numerous but small in size. As the grid opening enlarges the arc suppression time increases and larger sized degradation particles are produced. A fault is limited only by the maximum current amplitude of the source impedance and the interruption time of the breaker. Maximum fault power (I2T) determines time to failure. Particle size and count continues to grow until the distance from the point source of heat and the maximum grid hole diameter cause a cooling and blast zone buffer. At this point the production of larger particles decrease and smaller particles again increase. A plot of large particle size production with time seems to follow a bell shaped curve. The difference in the leading edge to the trailing edge of the curve is noted by the measurable increase in contact metals present in the oil. Arc suppression grids are constructed of cellulose and these particles can be distinguished from carbon and shiny metal particles by chemical microscopy. At temperatures above 300o C cellulose is destroyed and the resulting carbon particles are observed in the oil. Arc tip and arc shaft erosion can be measured by determination of the characteristic metals in oil and with chemical microscopy, which can distinguish between shiny metal and carbon particles. Oil quality assessment tests are also useful in identifying OCB problems. Dielectric breakdown voltage measurements, ASTM D-1816, are effected by moisture, metals, carbon particles and cellulose particles in the oil. Particles, especially carbon, also effect oil color. Since OCB’s are free breathing devices the moisture level is higher than that found in sealed components. Table 1 is a summary of the tests that we have incorporated in our OCB diagnostic program and the type of problem that can be determined with these technologies.

30

Insulating Oils Handbook Table 2

Table 1 Diagnostic Tests OCB Problem

Test(s)

Increased Contact Resistance

DGA

Contact Tip Erosion

DGA, Metals, Chemical Microscopy, Dielectric-1816

Arc Suppression Grid Degradation

DGA, Particle Count, Chemical Microscopy, Dielectric-1816, Color

th

90 Percentile Gas Concentrations in OCB Oil Samples Result(s)

Increased Hot Metal Gases, Increased Heating to Arcing Gas Ratios Hot Metal Gases, Metals Observed in Oil, Metal Particles Observed by Chemical Microscopy, Lowered Dielectric Breakdown Voltage Increased Fault Gas Levels, Large particles in the Oil, Cellulose Fibers, Decreased Dielectric Breakdown Voltage

IV. Diagnostic Protocols Once the appropriate analytical procedures were selected to ascertain the effect of OCB problems it became necessary to determine normal values for each of the measured parameters. We used a statistical approach to evaluate test data from problem free units in order to establish the norms. We then determined the ninetieth percentile values for each parameter, for several thousand OCB samples. For example, the 90th percentile individual fault gas concentration and the total dissolved combustible gas concentration for all samples evaluated are given in Table 2. Data for selected heating to arcing fault gas ratios was calculated in a similar manner. Similar calculations combined with field observations were used to establish norms for particle size distributions and metals in oil. Relevant IEEE guides are used to evaluate results of oil condition assessment tests. These values are all generic in nature and no attempt has made at this time to develop unit specific flag points.

Fault Gas

90th Percentile Concentration

Hydrogen

62

Carbon Monoxide

136

Methane

28

Ethane

14

Ethylene

71

Acetylene

173

Total Dissolved Combustible Gas

530

Diagnostic software has been developed to evaluate OCB samples according to our established norm values. OCB sample results are placed into three broad categories of Normal, Caution and Warning. Southern California Edison designates OCB condition numerically using a 3, 2, and 1 scale. Normal indicates that the sample should be retested according to the initial utility criteria. Caution indicates that the sample should be tested more frequently, again at a rate determined by utility protocols. Warning indicates that an internal inspection is appropriate. Figures 3, 4 and 5 are examples of test reports for samples that fit in each of these evaluation categories.

31

Insulating Oils Handbook Figure 3 OCB Condition: Normal (3) Serial number

20695 TK1

Counter #

Pole

C

Fluid Type

Model

Manufacturer Date

FPE

Gallons

267

KV Rating

69

Interrupt

Mineral

Hydrogen

2

Ethane

0

Between 15 and 25:

0

Between 50 and 100:

Methane

Ethylene

Acetylene

Carbon Monoxide

Carbon Dioxide

Between 2 and 5:

1

Between 5 and 15:

1

Between 25 and 50:

84

Greater than 100:

518

ISO Code:

Oxygen

24309

Total Dissolved Gas

78579

Carbon:

0.0973

Opacity

Nitrogen

Total Combustible Gas

Equivalent TCG Percent

Fibers:

53664

Metals:

88

Other

Condition Code: Normal (3)

3374895 749850 4084 571

Moisture

Color Number

Dielectric 1816

Silver

90

Chromium

0

23/20/13

Copper

Nickel

20

Phosphorous

50

Tin

10

Lead

20

Zinc

2.0

Tungsten

28

L2.0

20 1-24 L0.50

L0.50

L0.50

L0.50

L0.50

L0.50

L0.50

L0.50

L0.50

Narrative: No problems found. No action taken. Unit stayed in service, reset maintenance schedule.

Figure 4 OCB Condition: Caution (2) Serial number Model Pole

Manufacturer Date

28760

CG-38 MGE 1987

Hydrogen Methane Ethane

Ethylene

Acetylene

Carbon Monoxide Carbon Dioxide

Counter #

120

Fluid Type

Mineral

Gallons

KV Rating Interrupt 1

1

382

76145 0.0229

50557 24

2199309

Between 5 and 15:

3891922

Between 25 and 50:

2252

Between 50 and 100:

17

Total Dissolved Gas

Total Combustible Gas

Between 2 and 5:

2

2

Condition Code: Caution (2)

40

Between 15 and 25:

25182

Equivalent TCG Percent

38

1

Oxygen

Nitrogen

220

Greater than 100: ISO Code: Fibers:

98949 60 0

23/22/17

Moisture

Color Number

Dielectric 1816

Silver

Nickel

L0.50

Lead

L0.50

Carbon:

70

Tin

Opacity

4.0

Other

15

Narrative: Analysis indicated mild contact erosion, and poor oil quality. Remedial Action: Unit was put on ½ maintenance schedule and remained in service.

2.38

L0.50

Copper

Phosphorous

5

L3.0

10 1-24

Chromium

10

Metals:

30

Zinc

Tungsten

L0.50

L0.50 L0.50 L0.50 L0.50

32

Insulating Oils Handbook Figure 5 OCB Condition: Warning (1)

Serial number

318027-A

Counter #

608

Pole

A

Fluid Type

Mineral

Model

Manufacturer Date

FZO-69 Allis1953

Gallons

KV Rating Interrupt

Condition Code: Warning (1)

855 57 21

Hydrogen

7280

Ethane

729

Between 15 and 25:

9356

Between 50 and 100:

437

ISO Code:

Methane

Ethylene

Acetylene

Carbon Monoxide

Carbon Dioxide

Oxygen

6624 5424 91

44520

Nitrogen

24023

Total Combustible Gas

25706

Total Dissolved Gas

Equivalent TCG Percent

Between 2 and 5:

901411

Between 5 and 15:

3453273

Between 25 and 50:

221381

Greater than 100: Fibers:

Metals:

2645616 2462 0

29/28/24

Dielectric 1816

Silver

Chromium

Copper Nickel

23

L6.5

10 1-24 L0.50

L0.50 1.63

L0.50

10

Phosphorous

L0.50

Tin

L0.50

Tungsten

L0.50

10

94686

Carbon:

80

20.6182

Opacity

5.0

Other

Moisture

Color Number

0

Lead Zinc

L0.50

L0.50

Narrative: Oil sample obtained approximately 4 hours after a 30000 AMP, 3 cycle fault. Contacts evaluated at 25 percent degraded. Copper present due to shaft wear on movable contact. Grid not significantly degraded. Remedial Action: Rotated movable contact ¼ turn. Filtered and processed oil. General maintenance. Returned to service.

V. Sampling Protocols The overall objective of our OCB diagnostic program is to minimize the number of required internal inspections and thus to realize considerable maintenance cost savings. Utilities must decide when and at what frequency to sample their OCB’s. A sampling strategy has been developed by Mr. Alex Salinas at Southern California Edison, SCE, to determine when to draw the initial sample, when to draw subsequent samples and when to conduct an internal inspection. The entire sampling process is incorporated in their system software. The software, which maintains OCB operations data, generates an initial work order when any of three conditions are met: twenty interruptions, three hundred operations or five years from the last test. This first work order will be for an initial oil sample. The results of the initial test generate a code: 1=Schedule internal inspection, 2=Reset oil sample trigger at half the initial values (10 interruptions or 150 operations) and 3=Reset sample trigger at 20 interruptions or 300 operations. The software maintains all of the test data, resets the triggers and prints the work orders. This closed loop operation requires no operator intervention. A flow chart for the SCE protocol is given in Table 3.

Maintenance cost savings for the SCE program can be estimated considering the number of reduced internal inspections. SCE currently inspects about three hundred breakers a year, both oil filled and others. The oil filled breakers range in voltage class from 7.2 kV to 220 kV. Their largest number of breakers operates at 69 kV. Inspection costs range from 2K$ - 20K$ on OCB’s in the voltage range from 7.2 kV to 220 kV. Based on statistical evidence less than ten percent of the units tested will require an internal inspection. The savings promise to be considerable. Cinergy Corporation currently uses both condition based (CB) and fault adjusted operation count (FAO) as the initial triggers for breaker maintenance. The non-invasive condition based triggers used are thermography, ultrasonics, oil quality and dissolved gas analysis. The main invasive tests are ductor and power factor. The invasive tests are used minimally due to limited outage request acceptance. Fault adjusted operation count is a method that employs knowledge of the maximum fault amplitude based on source and circuit impedance and fault duration. This is used to

33

Insulating Oils Handbook Table 3 SCE Flow Chart

determine the estimated number of breaker operations before maintenance is needed. Unless the breaker employs the use of some form of I2T monitors it is still very difficult to determine true fault duty cycle. Additionally, due to deregulation and customer commitment, outages and internal inspections will be kept to a minimum. Although each test gives different positive information to determine maintenance interval, Cinergy has found the addition of oil particle analysis to determine grid and contact health invaluable to determine overall maintenance interval.

VI. Conclusions and Future Work Normal or threshold values for OCB test parameters are at this time generic in nature. Because of design variations unit specific normal values may be more appropriate. Unit specific test values will have to be empirically determined. We are maintaining a very detailed database so that we can develop unit specific normal values in the future. We are cooperating with utility clients to further evaluate testing frequency protocols. For example SCE tests the OCB oil every five years if the interruption (20) or operation

(300) criteria are not met. Can this time interval be extended without increasing system outages due to breaker failures? 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 longterm member of ASTM and IEEE and author of over fifty published articles, Dr. Jakob is a traveling lecturer to private and governmental agencies. He has been invited to speak at American Public Power meetings, ASTM symposia, conferences held by Doble, NETA, and AVO conferences, as well as other industrial organizations.

34

Insulating Oils Handbook

Sampling Transformer Oils Part One – How and Why to Take a Good Sample This three-part article deals with the art of sampling transformer oil (See page 37 for Part Two)

NETA World, Winter 2002-2003 by Lance R. Lewand Doble Engineering Company

The results obtained from the analysis of an insulating oil sample can provide unparalleled information concerning the condition of the insulating materials within electrical apparatus, life assessment, and the operating condition of the device. However, a sample that is not representative of the bulk oil insulation can provide erroneous information which can easily mislead maintenance personnel to incorrectly assess the condition of the oil or the electrical apparatus. In one case, samples taken from two transformers showed very high concentrations of hydrogen and no other gases, prompting maintenance personnel to give these units priority for diagnostic surveys. It was later found that the cause of the high hydrogen was a galvanic reaction occurring in the drain valves in which water was converted to hydrogen because of the interaction of a galvanized fitting with a dissimilar metal.

Why Sample? For in-service oil-filled electric apparatus, sampling of the oil provides a method to determine the condition of the solid and oil insulation as well as the operating condition of the apparatus without opening or de-energizing the apparatus. This is especially important in the present utility and industrial climates, as equipment outages for out-of-service testing have become very limited. Sampling provides a means to check the condition of oil in storage, whether it be new or used, and to determine if it complies with specifications such as TOPS, ASTM D 3487, IEC 60296, IEEE C57.106, or company specifications. Sampling can also help to determine: 1) If accidental mixing of different dielectric oils has taken place;

2) If the method of transportation contaminated the oil;

3) If the handling equipment to transfer the oil contaminated the product.

What is a Good Sample? Simply put, a good sample is one that is representative of the content of the bulk oil insulation. Since samples are usually retrieved from a drain valve or the attached sampling cock, preparation of that area is important to obtain a good sample. Cleaning the drain valve and the sampling cock inside and out is the first step in avoiding sample contamination. Cleaning the outside of the drain valve is just as important as cleaning the inside. The dirt and debris falling off the outside of the valve into the sample container during the sampling process can contaminate many samples. Most of the contamination in the apparatus consists of water and particles (paper fibers, metal particles, etc.), which over time will settle out on the bottom of the apparatus near the drain valve. This material needs to be flushed out of the system to get to the bulk oil insulation. It is necessary to remove at least one to two liters of oil from the drain valve, cap the drain valve, and then flush out the sampling cock before proceeding with sampling. On occasion, two liters will not be sufficient, especially when sampling a nonenergized transformer or certain OCBs and LTCs. Specific sampling techniques and precautions, especially those dealing with low volume electric equipment, are detailed in the Doble Reference Book on Insulating Oils and Gases and ASTM Practices D 923 and D 3613.

Good Samples Versus Bad Samples It is sometimes very clear to the laboratory performing the analysis on the oil that the sample was taken improperly. For example, the presence of free water or foreign objects such as insects, pipe sealing tape or putty are strong indicators that the drain valve was not adequately flushed out prior to sampling. Once analysis has begun and it is determined that there is a high or free water content coupled with a low dielectric strength, with all the other test results being acceptable, then it strongly indicates that the proper sampling

35

Insulating Oils Handbook technique was not adhered to. It may even imply that some chemical reactions were taking place in the drain valve that were not representative of the bulk oil insulation.

Lab Tests Most Easily Affected As indicated previously, the analytical tests most easily affected by sampling are dielectric strength and water content. This is due to the fact that drain valves are usually at very low points in the tanks where debris and water accumulation occurs. Water can also be present as a result of condensation that occurs in the drain valve, which is due to the position of the drain valve on the tank. In most cases the drain valve protrudes 15 to 30 centimeters (six to 12 inches) away from the main tank. From experiments performed at Doble Engineering, it was found that the oil in many of these valves varies in temperature from eight degrees Celsius to 15 degrees Celsius cooler than the bulk oil insulation. When oil or air has an elevated relative saturation or humidity and there is a significant cooling, condensation of water will occur. This is exactly what happens in a drain valve. Other analytical tests easily affected by sampling are dissolved metals, particulate metals, particle counts, dissolved gases-in-oil, and power factor. The concentration of metals, whether dissolved or in a particulate state, are especially impacted by the amount of cleaning performed on the drain valve and the amount of flushing that is performed. Debris that settles to the bottom of the apparatus and subsequently into the drain valve can consist of metal particles. In addition, just the simple fact of removing the drain-valve plug or opening the sampling cock will create particulate metals. This is due to the grinding of the surfaces between the valve body and the drain plug or sampling cock. In fact, it is becoming more apparent that that these types of samples should only be retrieved after a minimum of two (and sometimes three to four) liters of oil have been passed through the drain valve. The same is true of retrieving a sample for particle count where valve debris, whether inside or outside, can severely skew the results. The debris, soot, and grime that exist on the outside of the drain valve are of serious consequence, especially in industrial locations. This debris can be easily transferred to the sample bottle while the sampling process is taking place. This validates the importance of cleaning the outside of the valve prior to taking the actual sample. Dissolved gas-in-oil analysis is another test impacted by sampling, drain valve components, and sampling materials. When galvanic fittings (zinc coated) are used in the drain valve assembly — such as the drain plug — a galvanic reaction with water can cause very high levels of hydrogen to be produced. If this residue is not flushed out adequately then it will be transferred to the sample and included in the analysis, causing a level of concern that is not warranted. Galvanic plumbing fittings such as nipples can also have the same effect. Brass, bronze, stainless steel or black iron should be the only materials used. In addition, drain valve assemblies should not be composed of dissimilar metals as corrosion can result, which may end up in the sample. Debris, water and other ionic contaminants also affect the power factor test.

These materials increase dielectric loss, which increases the power factor. Incompatible inorganic and organic materials from the drain-valve stem packing or drain-plug sealants can also have the same effect on the power factor.

Costs Associated with a Bad Sample In the case of a single sample, the costs for routine oil quality analysis and DGA testing are just a very small fraction of the total costs associated with taking and analyzing a sample. Some of the items and costs associated with sampling and analysis are: ITEM Labor to take sample Materials to take sample Packaging and shipping cost Analysis cost Engineering evaluation of the data (10-15 min) TOTAL

COST ($) 275 15 8 70 35 403

Every situation is different, but in many cases the analysis cost is only about 17 percent of the entire sampling and data review process. In a situation where the sample has been determined to be nonrepresentative of the bulk oil insulation, the following additional costs may also be incurred: ITEM Labor to take original sample Materials to take original sample Packaging and shipping cost for original sample Analysis of original sample Engineering evaluation of the data (10-15 min) of original sample Additional engineering time to confirm sample was nonrepresentative Labor to take 2nd sample Materials to take 2nd sample Packaging and shipping cost for 2nd sample Analysis cost of 2nd sample Engineering evaluation of the data (10-15 min) of 2nd sample TOTAL

COST($) 275 15 8 70 35 35 275 15 8 70 50 856

The cost of taking a bad or nonrepresentative sample has more than doubled from the original total. This is in part due to the fact that review of data from the second sampling takes longer as there is a more critical and thorough review. If the original sample was not recognized as bad, the costs associated with that sample can be staggering. For example, a bad sample could cause a customer to try a remedial effort in an attempt to improve the condition of the insulating oil — such as processing the oil through clay or vacuum-pro-

36

Insulating Oils Handbook

cessing a transformer to remove moisture — then associated costs may skyrocket to between $10,000 and $30,000. This is one reason why Doble always recommends taking a second sample to confirm the results of the first before any remedial activities begin. Other factors, such as accidental sample switching or misidentification, can also be the source of an erroneous assessment. Part two of this series will cover the sampling practices to follow and the science of sampling.

“ASTM D 3613: Standard Practice for Sampling Electrical Insulating Oils for Gas Analysis and Determination of Water Content” in Electrical Insulating Oils and Gases; Electrical Protective Equipment, Annual Book of ASTM Standards, Vol. 10.03, ASTM, West Conshohocken, PA, 2001.

References

Lance Lewand received his BS degree at St. Mary’s College of Maryland in 1980. He has been employed by the Doble Engineering Company since 1992 and is currently Project Manager of Research in the materials laboratory and Product Manager for the DOMINOTM product line. Prior to his present position at Doble, he was the 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.

“Items of Interest” in The Doble Exchange, The Doble Engineering Company, Watertown, MA, USA, Volume 11, Number 3, September 1993, Page 4. Transformer Oil Purchase Specification (TOPS), edited by the Doble Oil Committee, Rev. TOPS-884, Doble Engineering Company, Watertown, MA. “ASTM D 3487: Standard Specification for Mineral Insulating Oil Used in Electrical Apparatus” in Electrical Insulating Oils and Gases; Electrical Protective Equipment, Annual Book of ASTM Standards, Vol. 10.03, ASTM, West Conshohocken, PA, 2001. “IEC 60296: Specification for Unused Mineral Insulating Oils for Transformers and Switchgear” International Electrotechnical Commission, 3, rue de Varembe, Geneva, Switzerland, 1982. “IEEE C57.106-1991: IEEE Guide for Acceptance and Maintenance of Insulating Oil in Equipment”, IEEE, 345 East 47th Street, New York, NY, 1992 Reference Book on Insulating Oils and Gases, edited by the Doble Client Committee on Oil Insulation, 1993, Doble Engineering Company, Watertown, MA. “ASTM D 923: Standard Practice for Sampling Electrical Insulating Oils” in Electrical Insulating Oils and Gases; Electrical Protective Equipment, Annual Book of ASTM Standards, Vol. 10.03, ASTM, West Conshohocken, PA, 2001.

Griffin, P. J. “Water in Transformers – So What!” National Grid Condition Monitoring Conference, May 1996.

37

Insulating Oils Handbook

Sampling Transformer Oils Part Two– Sampling Practices and the Science of Sampling This three-part article deals with the art of sampling transformer oil (See page 40 for Part Three)

NETA World, Spring 2003 by Lance R. Lewand Doble Engineering Company

The first part of this three-part series defined how and why to take a good sample and explored the costs associated with taking a bad sample. Part two covers sampling technique and factors influencing the sampling process. There are a number of industry-recognized standards that define the correct way to retrieve samples from electrical apparatus or storage containers. Some of the sources that list these sampling techniques include: • Doble: Reference Book on Insulating Liquids and Gases

• ASTM D 923: Standard Practice for Sampling Electrical Insulating Liquids

• ASTM D 3613: Standard Practice for Sampling Electrical Insulating Oils for Gas Analysis and Determination of Water Content • IEC 60475: Method of Sampling Liquid Dielectrics

• IEC 60567: Guide for the Sampling of Gases and of Oil from Oil-filled Electrical Equipment and for the Analysis of Free and Dissolved Gases These techniques have been developed over a number of years and have incorporated the expertise of many individuals. However, sampling technique involves much more than just taking the sample. It involves a more thorough knowledge of the information to be gained from taking a proper sample and includes sample site preparedness and site cleanup after sample retrieval. Some of the items that are a part of sample technique are: 1. Materials used to aid in retrieval of a sample. 2. Safety precautions to adhere to. 3. Environmental concerns.

4. Identification of the sample and apparatus information. 5. Final checks prior to sampling.

6. Taking the sample (cleaning and preparation of valves). 7. Cleanup after sample has been retrieved.

Materials Used Whoever takes the samples must be fully prepared for any eventuality that could occur at the sample site. For example, items such as sheet plastic, plastic bags, absorbent materials, flush oil containers, and catch pans are all important materials to have to prevent or clean up liquid spillage. It must be remembered that, in order to take a correct sample, some liquid waste will be generated. Of course, bottles and syringes will be needed as sample containers and must be of sufficient size to hold the volume of dielectric liquid necessary for the desired tests. Labels are required to sufficiently and correctly identify those containers. Make-up oil may be necessary to add oil to low volume devices. Bottled nitrogen may be needed to pressurize a transformer to relieve a negative pressure in order to get the dielectric liquid out of the apparatus. Tygon™ tubing or other compatible tubing is also necessary to direct the dielectric liquid from the drain valve to the flush container, sample bottle, and syringe. Tubing should only be used once and then discarded as the walls of the tubing have memory (gases, water, and other chemical compounds are held in the walls of the tubing) which can be transferred to the next sample. Incompatible tubing such as natural rubber or polyvinyl chloride will contaminate a sample. The appropriate tools and plumbing accessories must be on-site to manipulate the drain valve in order to retrieve the sample. Personal protective equipment such as nitrile gloves is used to protect personnel from the liquid dielectric and/ or polychlorinated biphenyls (PCBs). Personal protective equipment and safety practices to protect against electrical or physical hazards must also be present and observed.

38 Safety Precautions There are several safety precautions that must be followed in order to secure the well-being of the equipment as well as the personnel retrieving the sample. Death is not normally associated with sample-taking, but it has happened when electrical hazards have not been observed. Routines and complacency often contribute to a lax adherence to safety precautions. Some of the more critical safety precautions are: • Make sure there is positive pressure on the electrical apparatus.

• Take into consideration the remaining volume in low oil volume apparatus (this may require de-energizing the equipment). • De-energize instrument transformers before sampling. • Secure electrical dangers.

• Make sure Occupational Safety and Health Administration (OSHA) requirements are met. Making sure there is positive pressure on the electrical apparatus prior to sampling is the single most critical factor in assuring that the equipment survives the sampling procedure. Sampling of electrical equipment while under negative pressure will allow atmospheric air to be drawn into the equipment through the drain valve, which will rise through the transformer as bubbles. These bubbles are areas of weak dielectric strength and can easily cause failure of the apparatus through flashover. Most transformers have pressure gauges that allow determination of the actual pressure. If positive or negative pressure cannot be determined, then follow the procedure in ASTM D 923 to determine the pressure condition. This involves using a slug of oil in clear tubing attached to the sampling cock. If negative pressure does exist then no samples are to be drawn until that negative pressure is relieved. Sometimes this is as simple as adding dry nitrogen to the headspace of a transformer to pressurize the unit, or waiting until ambient temperature has increased to a sufficient degree to cause the expanding dielectric liquid to pressurize the apparatus. The remaining volume in some electrical apparatus — especially oil circuit breakers, bushings, load tap-changers, and small instrument transformers — is of serious concern. Electrical components are positioned at critical clearances and that distance is determined with liquid insulation present. If the liquid insulation level is too low the insulation between the energized components is now gas instead of the insulant, and the dielectric integrity becomes compromised. This is why it is important to check the liquid level not only before sampling but after as well, and this will aid in maintaining a safe operating environment. Instrument transformers must also be de-energized prior to sampling in order to secure the electrical hazards. Electrical hazards are especially prevalent in small distribution pole and pad-mounted transformers. Pole transformers do not usually have a sample valve so the lid

Insulating Oils Handbook of the transformer must be removed to take a sample. In addition, the primary and secondary voltage terminations are extremely close to personnel. This is also true of padmounted transformers where the secondary and sometimes primary cable or bus bar is within feet of the sample valve. Any wrong move by sample personnel and serious injury or death can result. Because of such concerns, OSHA has instituted lockout/tag procedures that must be adhered to secure against such dangers.

Environmental Concerns Dielectric liquid spillage as a result of sampling is a main environmental concern, as some of these liquids may still contain PCBs. The United States and many other countries have very strict guidelines for spill cleanup and notification of PCB materials. In the United States even one drop of liquid containing more than 50 parts per million of PCB is considered “improper disposal.” Even if the oil does not contain any PCBs or the spill is small and accidental there may be regulations dealing with the dielectric liquids’ release. It is, therefore, easier to prevent against spillage then to clean up after the spill has occurred. This is why many sampling personnel lay down plastic and absorbent materials under the drain valve prior to sampling and then use a catch pan to trap larger volumes of liquid.

Identification of the Sample and Apparatus Information Sample identification is an extremely vital aspect of the sampling process. Many laboratories receive samples that cannot be related to a specific device. Even if the sample was taken correctly, the lack of appropriate identification makes the sample useless. When sampling personnel retrieve samples from electrical apparatus, it should be done in a prescribed sequence so nothing is forgotten. The lack of information concerning an apparatus severely limits the laboratory in its ability to provide an in-depth diagnosis. Apparatus information such as the age, type of preservation system, and any previous incipient fault conditions or oil reclamation activities can alter a diagnosis. For instance, the Doble Materials Laboratory relies heavily on the type of preservation system that is part of the transformer to provide a diagnosis based on oil quality, dissolved gas analysis, and furanic compound results. In transformers that have a sealed conservator preservation system, oxygen and nitrogen values are expected to be below certain levels. If test values are above those levels, there may be several causes for this such as a breach in the bladder or diaphragm, another leak elsewhere on the transformer, or poor sampling. All these items would concern the operator of the equipment. However, if no information is provided or the information is incorrect then no diagnosis or an incorrect one will be provided by the laboratory. Laboratories also use the age and the type of preservation system of a transformer as exceedingly pertinent information when providing a diagnosis based on furanic compound results.

39

Insulating Oils Handbook Final Checks Adhering strictly to safety and environmental concerns will assist personnel in adequately preparing the site around the electrical apparatus to be sampled. However, specific attention should be given to some final checks before the sampling commences. These include: • Confirmation of positive tank pressure — again.

• Using the correct sample containers, both in size and compatibility. • Labeling the sample information completed.

• Protecting the sample from outside contamination.

• Relative humidity of ambient air less than 50 percent (avoid rain or snow conditions). • Temperature of dielectric liquid higher than or equal to the ambient air.

Checking for positive pressure is so critical that it requires a second check and must not be overlooked. As mentioned in Part one of this series, it is very difficult to perform the requested analysis when not enough sample volume exists. Therefore, it is very important to make sure the correct size sample container is used. If unsure of the sample volume requirements, it is better to provide more sample than to return to that apparatus at a later date to re-sample. Labeling samples with complete sample information prior to actually taking of samples is recommended. In this way, sample containers will not go unmarked and confusion can be avoided when multiple pieces of equipment are being sampled. Some geographic locations are inherently inhospitable to providing an environment where a good sample can be taken. Inhospitable locations include salt spray areas and high wind gusting areas that naturally kick up sand, dirt, soot, and other debris that can easily deposit foreign matter into an open sample container while it is being filled. In these instances protecting the sample from outside contamination may require special precautions. Really adverse environments may require totally enclosed sampling systems such as stainless steel cylinders to protect against outside contamination. The ambient environment in which a sample is taken can also contaminate the sample with excessive amounts of moisture. Taking samples during rain, hail, or snow conditions should be avoided. If the situation is completely unavoidable then necessary precautions must be enacted to keep the sample from absorbing any external moisture. It is recommended that sampling be performed only when the relative humidity conditions are less than 50 percent so as to minimize the amount of external moisture the sample will absorb. It is recognized that this may be unavoidable in certain geographical locations and during certain periods of the year, but every effort must be made to minimize external contaminants and have a sample that reflects the bulk liquid insulation.

The next and final part of this series will deal with taking the actual sample, sample storage, and transport.

References 1. Reference Book on Insulating Liquids and Gases, edited by the Doble Client Committee on Liquid Insulation, Doble Engineering Company, Watertown, MA, 1993. 2. “ASTM D 923: Standard Practice for Sampling Electrical Insulating Liquids” in Electrical Insulating Liquids and Gases; Electrical Protective Equipment, Annual Book of ASTM Standards, Vol. 10.03, ASTM, West Conshohocken, PA, 2001. 3. “ASTM D 3613: Standard Practice for Sampling Electrical Insulating Oils for Gas Analysis and Determination of Water Content” in Electrical Insulating Liquids and Gases; Electrical Protective Equipment, Annual Book of ASTM Standards, Vol. 10.03, ASTM, West Conshohocken, PA, 2001. 4. IEC 60475: Method of Sampling Liquid Dielectrics, International Electrotechnical Commission, 3 rue de Varembe, Geneva, Switzerland, 1974. 5. IEC 60567: Guide for the Sampling of Gases and of Oil from Oil-filled Electrical Equipment and for the Analysis of Free and Dissolved Gases, International Electrotechnical Commission, 3 rue de Varembe, Geneva, Switzerland, 1992. Lance Lewand received his BS degree at St. Mary’s College of Maryland in 1980. He has been employed by the Doble Engineering Company for the past seven years and is currently Project Manager of Research in the materials laboratory and Product Manager for the DOMINOTM product line. Prior to his present position at Doble, he was the 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.

40

Insulating Oils Handbook

Sampling Transformer Oils Part Three — Retrieving the Actual Sample This three-part article deals with the art of sampling transformer oil

NETA World, Summer 2003 by Lance R. Lewand Doble Engineering Company

The first part of this three-part series defined how and why to take a good sample and explored the costs associated with taking a bad sample. Part two covered sampling technique and factors influencing the sampling process. Part 3 will discuss the technique of taking an actual sample and methods for correctly storing and transporting a sample for analysis. Different dielectric liquids require sampling from different locations based on their relative density (specific gravity). In general, dielectric liquids with a relative density less than one should be sampled from the bottom drain valve whereas dielectric liquids with a relative density greater than one should be sampled from the top fill valve as long as it is below the liquid level. There are exceptions to this, and the sampling point can change throughout the life of the transformer. For instance, mineral oil transformers that have no drain valve are usually accessed and sampled through the top. Another example involves retrofilling of askarel transformers. When a transformer is filled with askarel, sampling should be performed from the top fill valve because the relative density is greater than one. However, many askarel transformers have been retrofilled and the askarel fluid replaced with silicone which has relative density less than one. In this case, the transformer should now be sampled from the bottom. Table 1 is a list of sampling points for various dielectric liquids in apparatus during routine testing. Sampling of drums, tankers, and other types of storage containers are performed in a different manner. Consult the previously referenced guides for specific procedures.

Table 1 Sampling Points for Various Dielectric Liquids in Apparatus Sample from Bottom

Sample from Top

Mineral oil Silicone R-Temp Midel 7131 Reoloec 138

Polychlorinated Biphenyls Trichlorobenzene Tetrachlorobenzene Wecosol Perchloroethylene

Beta Fluid

Shell Diala HFX WEMCO-FR MEPSOL Opticool

ALPHA-1 FLUID

Polyalphaolefins (PAOs) BIOTEMP

BIOTRANS ECO Fluid

EDISOL TR

ENVIROTEMP® FR3 ENVIROTEMP 200

Once the correct valve from which to retrieve the sample has been determined, that valve should be prepared for taking of the sample. As mentioned previously, check for positive pressure on the apparatus before opening the drain valve. Adequate preparation of the valve for sampling consists of the following:

41

Insulating Oils Handbook Clean the outside of the valve to remove any loose debris that may fall into the sample.

Make sure the valve and sampling cock are closed before removing the drain plug. Prepare the area under the valve with absorbent materials and a catch pan. Slowly remove the drain plug.

Valve Seat

Transformer Tank

Clean the inside of the valve with a lint-free cloth.

Drain Plug

Reinsert the drain plug and then purge the sampling cock.

Close the drain valve and remove the drain plug again, remembering to be prepared to catch left over oil from the sampling cock purge. Clean the inside of the valve again.

Install brass, bronze, black iron, or stainless steel adapters to the drain valve and then to a hose barb so that tubing can be attached. A diagram of a two-inch globe valve is shown in Figure 1. Globe valves are used most often in transformer construction as they provide the best seal against pressure and vacuum.

Sampling Cock

Water and Debris Accumulation

Figure 2 — Debris and Water in Sampling Cock

the main drain valve. Once the adapters are all installed with the hose barb, the final assembly may resemble the shown in Figure 3. Once the valve is totally prepared, sampling can commence. The practices as referenced previously all provide very detailed information concerning taking the actual sample. However, listed below are additional points to remember:

Hand Wheel Valve Stem Packing Nut Sampling Cock

Valve Seat Valve Body

Sampling Cock

Valve Opening

Side View – Cutaway

Valve Body Adapter

Front View

Figure 1 — Globe Valve Diagram

Although the procedure listed above sounds like a lot of extra work, it is necessary in order to retrieve a sample free from outside contamination. Doble Engineering recommends that samples be retrieved from the main drain rather than the sampling cock. Although convenient, the sampling cock is connected by a very small hole to an area between the drain plug and the valve seat. This is the area that accumulates all the debris and water as shown in Figure 2. Special care must be taken to purge this area. Even after repeated flushings, the sampling cock is rarely totally clean, and water and debris will break free and subsequently contaminate the sample. However, flushing of the sampling cock is important as it does remove a large portion of the water and debris prior to taking the sample through

Hose Barb Tubing

Figure 3 — Drain Valve with Adapter, Hose Barb and Tubing

Flush at least two to four liters of dielectric liquid through the valve prior to taking a sample.

If taking both syringe and bottle samples, take bottle samples first and syringe samples last. Rinse bottles two to three times with about one third of their volume prior to taking actual samples.

42 Rinse syringes two to three times prior to taking actual samples. Fill the bottles without causing aeration or turbulence to the oils. If using glass bottles, fill to about 2 to 3 cm of the top and secure the caps.

If using metal cylinders, metal cans or plastic bottles fill to overflowing and close or cap. The flushing procedure is very important in order to remove debris and water from the valve to get a sample that reflects the bulk liquid insulation. Cast iron valves tend to retain more moisture on valve walls then do brass, bronze, or stainless, so more flush liquid may be required. De-energized equipment may require more flush liquid (eight to 15 liters) to clean the valve, as more condensation of water occurs and settles to the bottom as the apparatus cools. On low-volume apparatus this should be monitored closely. As mentioned earlier, when multiple samples are required, Doble recommends taking the bottle sample first and syringe sample last for several reasons. One reason is that the water content is usually performed on the syringe sample so in addition to the original flushing that is performed, taking the bottle samples first provides additional flushing. The other reason is the syringe sample is used for the DGA test, which is the most critical of all the tests, as it provides information on the operating condition of the transformer. Hopefully, the additional flushing caused by the filling of the bottle sample will provide a syringe sample that is best representative of the bulk liquid insulation. Rinsing a bottle several times removes any debris remaining from the bottle manufacturing process and conditions the container to receive the sample by warming the walls of the container so water condensation does not occur during sampling. The same is true of the syringe, where flushing and purging helps to remove any debris and moisture, coats the plunger to create an adequate seal, and helps to remove air bubbles. Once the syringe is filled, any air bubbles remaining must be quickly removed. However, if gas bubbles appear after the dielectric liquid has cooled then do not release those bubbles, as they are gases that have just come out of solution but still comprise the sample. Syringe samples must also be shielded from the sunlight to prevent photo-degradation of sample. When filling bottles with the dielectric-liquid sample, aeration and turbulence must be avoided. Aeration and turbulence will cause air and water to be trapped in the sample, thus increasing the water content and possibly affecting some of the other properties of the oil. Glass bottles are not filled to the very top to avoid breakage due to the expansion or the contraction of the liquid. Metal cylinders, metal cans, and plastic bottles do not suffer from this problem and, therefore, may be filled to overflowing and sealed.

Insulating Oils Handbook Cleanup Cleanup is a necessary step of the sampling activity. The area should be left cleaner than found so possible hazards can be minimized for the next sampling crew. Make sure that drain valves and sampling cocks are wiped clean of oil and closed tightly. Replace drain plugs using the correct type of pipe sealant so that they are easily removed the next time the apparatus is sampled. Remove all debris and tools from the area, and clean up any liquid spillage. In addition, record the top oil temperature of the apparatus so that the relative saturation can be calculated, and make sure that the samples are adequately labeled.

Observations and Recommendations Sampling of the liquid dielectrics from electrical apparatus is a nonintrusive way to permit access to helpful information regarding the operating condition of the apparatus. Physical, electrical, and chemical tests performed on the sample can permit an educated determination of the condition of the solid and liquid insulation in the apparatus or the existence of an incipient fault condition. Tests of the liquid dielectric usually supplement tests performed on the apparatus proper, often supporting or assisting in the interpretation of such tests. These tests are especially helpful in cases where apparatus cannot be removed from service for complete testing or where complete testing can only be performed infrequently. The first requirement of liquid dielectric testing is a representative sample of the material in question, what has been referred to as “good” samples. A “bad” sample is not a sample. A “bad” sample represents the loss of time and expense and the possible overlooking of a hazardous condition in its incipient or developing stage. Bad sampling practices resulting in bad samples are to be avoided. This article has attempted, sometimes repetitiously, to summarize reasonable and effective sampling procedures. It has discussed sampling containers, their labeling, sampling care, sampling techniques, cleanliness before and after sampling, sample storage and transport, and safety, and environmental concerns. A review of practices on each client system, in light of these recommendations, may result in some “tightening up” of routine, familiar practices and lead to fewer “bad” and hopefully all “good” samples in the future. Lance Lewand received his BS degree at 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 in the Doble Materials Laboratory and Product Manager for the DOMINOTM product line. Prior to his present position at Doble, he was the 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.

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Insulating Oils Handbook

Corrosive Sulfur in Transformer Systems NETA World, Fall 2003 by Lance R. Lewand Doble Engineering Company

Corrosive sulfur and the effect that it has in transformer systems can be significant. The extent of the corrosion damage caused by sulfur can be so severe as to cause failure of the apparatus. The problems with corrosive sulfur have been recognized for quite some time. As early as 1948, F.M. Clark and E.L. Raab issued a report on the subject for method development within ASTM. Sulfur is found in many materials of transformer construction, including the copper, paper insulation, gaskets, and oil. Not all sulfur compounds are considered corrosive, but the tendency to operate transformers at substantially higher temperatures can aggravate an already present corrosive sulfur condition or convert stable compounds into reactive ones that will cause damage.

Presence of Sulfur in Mineral Oil There are different types of sulfur compounds found in refined transformer oil. Not all types, however, are considered to be corrosive or reactive. Elemental sulfur and sulfur compounds in concentrations up to 20 percent are present in the crude oil used to make transformer oil. There are five basic groups of sulfur and sulfur compounds found in crude oil (see Table 1). As shown in Table 1, elemental sulfur and the sulfurcontaining mercaptans are very reactive followed by sulfides. Reactive sulfur is mainly in the form of organic sulfur compounds like R-SH, where the sulfur is attached at the end of an organic molecule. When the molecule is more complex, for instance when the sulfur is surrounded or contained within the molecule, then the sulfur compounds are more stable and less reactive, as in R-S S-R. Thiophenes are the most stable of all these sulfur compounds. Some sulfur compounds can actually aid in the oxidation stability of the transformer oil and may also act as metal passivators and deactivators reducing the catalytic effect on oil oxidation in transformers. The goal of the refining

Table 1 Sulfur and Sulfur Compounds Found in Crude Oil GROUP

CHEMICAL FORMULA

Elemental (Free) Sulfur

S

Sulfides (thio-ethers)

R-S-R1

Mercaptans (thiols)

R-SH

Disulfides

R-S•S-R

Thiophenes

Five-membered ring containing sulfur

REACTIVITY Very Reactive Very Reactive Reactive

Stable

Very Stable

R = paraffin with straight or branched chain hydrocarbon or cyclic hydrocarbon

process is to either remove or convert many of the corrosive and reactive sulfur species (i.e., elemental sulfur, mercaptans, and sulfides) to more stable compounds such as thiophenes in an unsaturated ring and disulfides in a saturated form. The steps in the refining process that aid in this effort are atmospheric distillation at various temperatures, vacuum distillation, catalytic reaction, and hydro-treating and hydrogeneration. It should be recognized that the refining process is not always totally successful, as incomplete refining may leave small quantities of mercaptans behind or the hydrogenation process may produce elemental sulfur as opposed to hydrogen sulfide. After refining, there is some sulfur, left but the total sulfur (comprised of the five groups listed in Table 1) remaining in new oil product is expected to be from 0.02 percent to 1 percent. This information was slightly dated so the Doble Materials Laboratory analyzed several samples and found that most oils had a very low total sulfur content as shown in Table 2.

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Insulating Oils Handbook Table 2 Total Sulfur Content in some US Oils

Oil

Sulfur Content

Calumet Caltran 60-08

0.006%

Ergon Hyvolt II

0.006%

Cross Oil CrossTran 106 San Joaquin Hytrans 61

Shell Diala AX from Deer Park

0.012%