CASE STUDIES INVOLVING INSULATING LIQUIDS AND MATERIALS FROM THE DOBLE MATERIALS LABORATORIES

Transcription

1 CASE STUDIES INVOLVING INSULATING LIQUIDS AND MATERIALS FROM THE DOBLE MATERIALS LABORATORIES Lance R. Lewand and Paul J. Griffin Doble Engineering Company, USA ABSTRACT This paper discusses cases that involved problems with apparatus or insulating materials that have been detected and studied using oil tests to help determine the root cause. Several of the cases involved dissolved gas analysis and detection of fault conditions. This includes problems that produced hydrogen besides partial discharge activity, ethylene to ethane ratios to better evaluate when paper in involved in localized high-temperature overheating problems, and testing for stray gas production. One case is on oil quality and examines the formation of elemental (free) sulfur in oils that have stable corrosive sulfur compounds but have been exposed to very high temperatures. Another case presented is on oil tests to evaluate the condition of an oil circuit breaker. The final case is on materials and how a compromised o-ring was shown to be improperly manufactured. INTRODUCTION Diagnostics for evaluating electric apparatus can be developed using laboratory studies and empirical evidence from testing and investigations. Such has been the case with dissolved gas-in-oil analysis, the most important test in the industry for condition assessment of transformers. A number of methods have been used to analyze the dissolved gas analysis (DGA) data and often provide enough information when combined with electrical testing and internal inspections to find the source of faults. In some cases the source of the gassing is not clear and additional methods need to be used to find the source of the gassing. Stray gassing, associated with low temperature heating of some oils has been investigated in some cases where excessive gassing of transformers has been detected with no known obvious fault. It has also been used to determine the presence of contaminants, their impact on gassing, and to assess the success of remediation efforts to remove those contaminants. Methods commonly used in the laboratory for the assessment of the main tanks of transformers, such as DGA, particle count, metals analysis, dielectric breakdown voltage, water content and neutralization number have been packaged together to create diagnostic test programs for condition assessment of load tap changers (LTCs) and oil circuit breakers (OCBs). These diagnostic programs are useful in assessing the condition of the apparatus without taking the equipment out of service. It allows a means to evaluate the equipment between long time frames of actual physical maintenance outages and thus has become a powerful tool for the maintenance engineer. Testing of materials is not limited to insulating liquids. Other tests can be used to evaluate the condition of a solid material, such as an o-ring. There are a variety of tests which aid in ascertaining the suitability of solid materials for use in electric apparatus and to determine the root cause if it should fail. Material compatibility testing which marries the material to be used in an electrical apparatus to the oil or other insulating liquid is not as commonly performed today as in the past. This type of testing, however, enables the user to weed out materials that might not hold up under in-service conditions and is yet another tool that has significant value. The six cases provided touch on each of these topics.

2 Case 1: Source of Hydrogen Generation Manufacturer: General Electric Year: 1983 Service Time: 19 years kv: 230/69 MVA: 22/32/40/45 Expansion/Preservation System: Nitrogen Blanket This transformer was one of four units at a substation. The units were heavily loaded at the time of sampling and the owner was concerned with the possibility of having to remove the unit from service because of excessive gas generation indicating a serious problem. The gassing is shown in Figure 1 over about a four and one half month period. The gassing suggested that only the hydrogen was increasing substantially. The hydrocarbon gasses ethane and ethylene seemed to be decreasing possibly from some previous overheating event. The rate of hydrogen generation was moderate between March and July at a little over 1 ppm per day, but increased to 27 ppm per day in July. The typical gassing pattern that is predominately hydrogen is partial discharge (PD) activity. Table 1 Gassing Trend in ppm, v/v Gas July 26 July 10 March 13 Hydrogen Methane Ethane Ethylene Acetylene Carbon Monoxide The gassing pattern for partial discharge is predominately hydrogen with lesser amounts of methane, ethane, and trace amounts of ethylene and in some cases traces of acetylene too. The ratio of combustible gases typical of partial discharge activity is shown in Table 2 [1, 2]. As can be seen most of the gases are hydrogen and methane. The values for Reference 2 is an average taken from the gassing characteristics of a gas adsorbing and gas evolving oil in terms of gassing tendency as measured by ASTM D In IEC one of the key ratios to describe partial discharge is the methane to hydrogen ratio being <0.1. It also notes that this ratio can be between depending on the application and still be indicative of partial discharge activity. In a simplified scheme it uses <0.2 as the methane to hydrogen ratio which would be consistent with the values given in references 1 and 2. Another method to determine type of condition is the Duval triangle [3]. The Duval triangle uses the relative composition of methane, ethylene, and acetylene as the three sides. PD is characterized by methane makes up 98% of the combination of methane, ethylene and acetylene. More recently Duval has developed triangles for low temperature heating and partial discharge activity. In addition, it includes gas generation from stray gassing which is discussed later in this paper. One triangle is for low temperature faults using hydrogen, methane and ethane. Here PD is defined in a narrow zone with less than 2% ethane, 2-15% methane and mostly hydrogen. Another low temperature Duval triangle for mineral oils uses methane, ethane and ethylene. Here PD is characterized as a small band with trace amount of ethylene, low percentage of ethane and high percentage of methane. Table 2 Typical Gassing Pattern for Partial Discharge Activity Gas Typical PD Pattern, Ref. 1 Typical PD Pattern, Ref. 2 Hydrogen Methane Ethane Ethylene Acetylene Carbon Monoxide

3 When high relative amounts of hydrogen are detected by DGA analysis one must consider possible alternative sources than PD as the source. These include stray gassing, reaction of iron with free water, electrolysis of free water, core heating, catalytic formation from reaction with metals, and heating of other organic materials. Stray gassing is the low temperature gassing behavior of oils. This behavior has been described in several papers [3, 4, and 5]. The predominant gas formed is hydrogen, similar to that from partial discharge activity. Under normal gassing behavior the amount of stray gases expected to be generated would be relatively steady at a slow to moderate rate of gassing. In most cases this would not result in extremely high amounts of combustible gases. In a Doble study on 47 oils in 2009 on stray gassing the relative amounts of gases on average were determined and are shown in Table 3. For most oils this stray gassing behavior would not be expected to be confused with a serious fault condition. With very high gassing oils though, there could be some confusion with PD activity during the early stages of gassing. It can be seen in Table 3 that for a high stray gassing oil, mostly only hydrogen and some carbon monoxide are formed. This might be distinctive from PD activity because of the extremely low amount of methane. However, if there is some low temperature heating of oil, it can have the same pattern as PD activity. Another type of problem that can cause high hydrogen in transformers is the breakdown of free water. Sheppard showed that free water introduced to core steel in the presence of oxygen from air would yield hydrogen and iron oxide [6]. Christensen and Ohlsson showed that free water introduced into a transformer could indeed produce such reactions. This was detected using a continuous hydrogen detector when circulating oil that unintentionally contained free water in the conservator tank into the main tank of a transformer [7]. They proposed a corrosion mechanism of: 3H 2 O + 2Fe 3H 2 + Fe 2 O 3. Another means of formation of hydrogen from free water due to electrolysis in galvanized valves [8] has been shown. This is only in the presence of free water that can condense in the bottom drain valve at cooler temperatures. The only combustible gas generated in each of these cases is hydrogen. Table 3 Typical Gassing Pattern for Stray Gassing on Average Gas Nitrogen Purged % Air Purged % High Stray Gassing Oil, % Hydrogen Methane Ethane Ethylene Acetylene Carbon Monoxide Voltage over-excitation conditions have been shown to generate hydrogen from overheating of the core [9]. Typical of this gassing pattern is an above normal generation rate for some period of time that eventually seems to level off. Here the gassing pattern shown in laboratory tests is almost entirely hydrogen when tested between C. Traces of hydrocarbon gases were detected at a few of the test temperatures and some carbon monoxide but almost all of the gas was hydrogen. Transformers thought to be gassing from this condition however exhibited gassing patterns typical of partial discharge activity with methane to hydrogen ratios <0.2 and some <0.1 but not so low to appear to be from another source of gassing. In a study in Japan it was shown that some stainless steel materials could generate hydrogen from the catalytic breakdown of the oil [10]. Another source of hydrogen from metal materials is galvanized materials in transformers. This has been discussed but does not appear to have been documented in the literature. Additionally, hydrogen gassing has been found from an the improperly cured primer used in a radiator [11] and the Doble labs experienced hydrogen generation from an incompatible bladder polymer at fairly low temperatures (<80 C) A possible source of mistaken hydrogen formation is from helium gas. Helium gas can be used to leak check transformers. Helium and hydrogen can be separated by gas chromatography using the right columns and 3

4 conditions. If proper care is not taken to separate these gases, then helium used for leak checking can be confused for hydrogen. A population of transformers with high hydrogen tested during the previous year was examined. All units had a minimum hydrogen content of 1000 ppm, from the main tank, and not from an arcing or high temperature overheating condition. From these units it was seen that most of them had a methane/hydrogen ratio of < 0.2. Of a total of 156 units that met the criteria, 15 had values above 0.2. It is thought that these units might have heating and partial discharge issues. Twenty transformers had methane/hydrogen ratios < 0.02 suggesting in some of these cases that other causes were possible. It is quite possible too that even some of those in the range of 0.02 to 0.2 could have been due to other sources than partial discharge, but it would be expected that most of them did represent PD faults. CONCLUSIONS for Case 1 In this Case 1 it was recommended to first to eliminate the possibility that there was condensation in the valve and the hydrogen was being formed from electrolysis of free water. To clean the valve it was wiped out and several gallons of oil was flushed through it and a fresh sample taken. Once the valve was well cleaned and flushed the hydrogen returned to normal levels indicating that the source was from free water in the valve. Although most cases that appear to be partial discharge are likely correctly identified, it is quite possible for a source of high hydrogen to be from other causes. When gassing levels are high it would be a good practice to confirm the presence of PD before attempting remedial action. A check list of possibilities has been provided for this purpose. Case 2: New Approach to Assessing Involvement of Paper in High Temperature Overheating Faults Manufacturer: Westinghouse Year: 1972 Service Time: 23 years kv: 17.2/136.8 MVA: 560 Expansion/Preservation System: Nitrogen Blanket Cooling: Forced oil and Forced Air (FOFA) This case involves a transformer that had high temperature localized overheating as indicated by the dissolved gasin-oil pattern. Examples of the gas data are given at three times over a five year period in Table 4. This transformer has been discussed in a previous paper where the fault was identified [12]. This transformer was from a family that has been known to have some core heating issues. For this reason some tolerance was given to gassing patterns that indicated localized high temperature overheating. This pattern was characterized by formation of hydrocarbon gases methane and ethylene with lesser amounts of ethane and in some cases small amounts of acetylene. However, as can be seen from the data, the gassing rate became high in 1994, and then extremely high before finally being removed from service in The carbon oxide gases were quite low and the ratio was indicative of general heating of the windings, and was not unusual for a shell-form design. Subsequent investigation revealed that the problem was in the lead to the series connection and that the copper strands in the lead were melted and the paper charred locally. A review of the problem suggested that the small amount of paper involved would not generate much carbon oxide gases [13]. Although this problem was caught before catastrophic failure in the field, it might have been responded to more quickly if it was know that the fault involved paper-wrapped conductor. When there is overheating in transformers that involves paper insulation at high temperature, it is of much greater concern as this is the main insulation and at high temperatures where large amounts of methane and ethylene are generated, paper life next to the conductor can be measured in hours and days. More recently there was a presentation [14] that indicated that core and winding faults involving high temperature heating could be distinguished in part by looking at the ethylene/ethane ratio. A ratio > 4:1 was used as an indicator of core related problems. Reviewing the previous data and considering the ethylene/ethane ratio, it can be seen that when the gassing was associated with core heating typical of this family the ethylene to ethane ratio was greater than 4

5 4:1. When the gassing rate increased to high and extremely high levels the ratio was significantly less than 4:1. This appears to be another means for assessing if paper was involved in localized high temperature overheating. Table 4 Dissolved Gas Results Indicating High Temperature Overheating, ppm Gas 4/27/95 4/8/94 4/27/90 Oxygen Nitrogen Hydrogen Methane Ethane Ethylene Acetylene Carbon Monoxide Carbon Dioxide CO2/CO ratio 88:1 162:1 4570:1 Ethylene/Ethane 2.9:1 2.9:1 4.8:1 Gassing rate, ppm/day 327 past month 3.9 past year 1.2 past year Doble started a study to further investigate the ethylene/ethane ratio, but in the context of ethylene/ethane ratio indicating the following: Bare metal fault if > 4:1 Paper wrapped conductor fault < 4:1 Using these ratios 25 cases were examined. Of these, six would have incorrectly indicated if the fault involved paper insulation and 19 would have correctly indicated if the fault included paper. Based on carbon oxide generation, many of these cases the problem was indeterminate or misleading. Therefore it is good to have other indicators of involvement of paper when faults are localized high temperature overheating. CONLCUSIONS for Case 2 Based on this preliminary study it appears that the ethylene to ethane ratio can be helpful indicating paper has been involved in a fault when carbon oxides are still acceptable. Conversely it can be an indicator that paper is not likely involved in the fault. This ratio is not always a correct predictor and should be taken only as a possible indicator. Case 3: Investigation into Stray Gassing of a Non-Energized Transformer This case involved three sister transformers that were manufactured in France and then shipped to the United States for installation. The transformer information is provided below: Manufacturer: Jeaumont-Schneider Serial Numbers: 50124, 50125, Year: 2002 Service Time: None kv: 525/230 kv, 3 phase, Auto MVA: 598 MVA Expansion/Preservation System: Sealed preservation system with bladder Cooling: OA/FA/FOA Design Type: Shell Form Volume of oil: 17,310 gallons Configuration: 525 WYE/230 WYE BIL Rating: 1425 kv /825 kv 5

6 Upon being manufactured in France, the coils went through the vapor phase process, were then landed in the tank and the complete transformers were processed and filled with new Esso Univolt 54 oil produced in France. The units passed all factory testing including dissolved gas-in-oil analysis (DGA) during heat runs and were then readied for shipment to the United States by undressing the transformers and removing the oil. After installation of the transformers on the pad and dressing of the units, the oil fill commenced. During this procedure something was noticed to be amiss. During the vacuum processing of the oil, the utility required a total gas content of the oil to be less than 0.5% by volume (5000 ppm). In their experience no more than two passes was ever required to reduce the total gas level to below the 0.5% level, but these units had required up to 6 passes (recirculations) to get the gas content below the required maximum level. The processing trailers were examined and tested, yet no issues could be found. The transformer tanks had held vacuum without any issues, so there was no excess air ingress. In addition, numerous samples were sent for DGA to several laboratories to make sure it was not a laboratory or sampling error. The utility was using CrossTrans 206, a US product, as the transformer oil and had used it quite frequently in the past with no issues. The utility continued with the processing until the units were filled despite the issues that were encountered. This process was completed in September of During that time, the units were not energized. However, the utility continued to sample the transformers on a regular, about biweekly basis. The DGA and oil quality results are provided in Tables 5 and 6. Table 5 DGA Results for Non-energized Transformer, S/N 50125, ppm Sample Date Hydrogen Oxygen Nitrogen Methane Carbon Monoxide Ethane Carbon Dioxide Ethylene Acetylene 10/01/ , /30/ /12/ /03/ , /10/ /12/ /03/ /23/ /13/ Table 6 Oil Quality Results for Non-Energized Transformer, S/N 50125, ppm Sample Date Top Oil Temp. Water Neut. No. IFT Color Dielectric Specific Gravity PF at 100 C Inhibitor C ppm mg KOH/g mn/m kv % % 10/02/ /30/ /12/ /10/ /23/ /13/ ASTM Test D 1533 D 974 D971 D 1500 D 1816 D 1298 D 924 D 2668 After the review of these results, Doble was asked to aid in the investigation. The continued gassing of the transformers that were not energized was troublesome, as there could not have been any electrical or thermal fault conditions. The top oil temperatures provided in Table 6 indicated that the temperature of the oil was that of the ambient and thus not being heated in any other way. Continued production of ethylene, ethane and hydrogen with the presence of acetylene was felt to be due to some sort of contamination. The oil quality results in Table 6 bore this out. The Doble laboratories routinely conducted oil quality tests on new CrossTrans 206 oil in tankers delivered to utility installations with the following new oil quality characteristics as listed in Table 7 and compared with the problem oil. 6

7 Table 7 Oil from Unit Compared to New CrossTrans 206 Oil Test Results ASTM Test Units Data from initial lab Confirmation Data from Doble lab New CrossTrans 206 TOPS Specification Values for New oil when Delivered [15] Neutralization Number, D 974 mg KOH/g 0.01 < Interfacial Tension, D 971 mn/m >40 Color, D L 1.5 L Power Factor at 100 C, D 924 % The results in Table 7 indicated a degraded oil when compared to the values expected for new oil upon receipt. Although IEEE C [16] allows a slight degradation in oil quality upon installation into a transformer, the change in all four tests given in Table 7, especially the interfacial tension and power factor at 100 C values was sufficient to initiate an investigation. The DGA analysis was also repeated and verified that the combustible gases had been generated. Early in the investigation there was the suggestion that it was possible that some residual vapor phase fluid may have been present in the windings and was the cause of the increasing gassing especially of ethane. Testing of the oil for flash and fire points and an infrared scan of the oil did not show this to be the case. Furanic compound analysis was also performed to determine if accidental overheating of the cellulosic insulation during factory testing was a contributor but this was ruled out as the furanic compounds were less than 5 ug/l. Other testing, however did reveal issues with the oil as indicated in Table 8. Table 8 Comparison of CrossTrans 206 Oil Quality Results from JST Transformers and Doble Survey 95 [17] ASTM Test Units Oil in Unit Oil in Unit Oil in Unit Neutralization Number, D 974 mg KOH/g <0.01 Interfacial Tension, D 971 mn/m Color, D L L 0.5 Power Factor at 25 C, D 924 % % Power Factor at 100 C, D 924 % % Specific Gravity, D Viscosity at 40 C cst Sludge Free Life (SFL), Doble Test Hours >88 88 >88 >88 Gassing Tendency, D 2300 ul/min Oxidation Testing by D 2440 Neut. No. at 72 hours Sludge at 72 hours Neut. No. at 164 hours Sludge at 164 hours mg KOH/g % mg KOH/g % <0.01 < <0.01 < Data from Doble Survey 95 <0.01 <0.01 <0.01 <0.01 The oil in all three transformers was contaminated to some degree, but the oil in Unit was the worse overall. All the test results listed were impacted to varying degrees of which the IFT, color, power factor at 100 C, and oxidation stability tests were negatively impacted the most. One additional oxidation test was performed in order to try and gauge the severity of the contamination. This was the Doble Power Factor Valued Oxidation Test (PFVO). The test was conducted by adding 300 mls of the oil to be tested into a glass vessel. The glass vessel was fitted with a stainless steel measuring capacitor with an abraded copper catalyst inserted into it. The sample was then aged for 140 hours at 95 C in the presence of bubbling air controlled at a specific rate and the power factor automatically measured every 15 minutes for 140 hours. The power factor should not increase above 4.5% during that time. The samples were tested in duplicate. The plot in Figure 1 shows the results of that testing. 7

8 PFVO Graph of CrossTrans 206 oil in Unit and From Doble Survey 95 Figure 1 As shown in Figure 1, the oxidation stability as measured by the Doble PFVO test was completely different from new oil CrossTrans 206 oil, even though they should have basically the same characteristics. Besides the oil quality tests, the DGA analysis had shown gases that were continuing to be generated in a transformer that had not been energized. This was not acceptable as the DGA diagnostics used to determine an incipient fault condition would be masked by this gassing behavior associated with the contamination. In 1991 Doble had determined that under certain thermal conditions (80 to 120 C), some oils could produce combustible gases that were not related to faults in transformer [18]. A CIGRE working group had noticed a similar trend and developed a method to determine this gassing behavior. This abnormal gassing behavior became known as stray gassing [19]. At the time of this case with the JST transformers, Doble had been heavily involved with this analysis and had developed a standard test method which was adopted as ASTM D 7150 [20]. In an effort to determine if the filling oil (CrossTrans 206) could be adding to the problem, stray gassing experiments were performed on each oil using CIGRE guidelines, but using nitrogen instead of air as the purge gas as these were sealed conservator transformers (bladder). The stray gassing experiment involved sparging an oil with nitrogen for 30 minutes, placing that oil in a syringe and heating the oil for 16 hours at 120 C and then performing a DGA analysis. In this experiment, a sample was taken before heating as well to get a baseline. As shown in the results in Table 9, the initial samples before heating were high in nitrogen because of the purging but had a very low concentration of the other gases. After heating, the oil from unit showed production of a few parts per million (ppm) of some combustible gases as expected. However, the sample from unit showed a higher production of combustible gases. This type of gassing behavior is unusual for the same brand of oil. This suggests that the oil was contaminated with some type of material which was causing excessive gassing. The source of the contamination was unknown but could be due to the tanker delivering the oil, any storage facilities, the oil processing trailer or some material used in construction of the transformer that was now leaching out of the system. 8

9 Table 9 DGA Results From Stray Gassing Investigation, ppm v/v Gas Oil As Received Oil After Being Sparged with N 2 S/N 50124, after 120 C for 16 Hrs S/N 50125, after 120 C for 16 Hrs Hydrogen Oxygen Nitrogen Methane Carbon Monoxide Ethane Carbon Dioxide Ethylene Acetylene TCG The gassing patterns for and are clearly different, especially for the same product delivered at the same time. An infrared scan of each sample confirmed that the oils were the same product. The only difference was that the oil from the was removed and put into the problem unit as leaks had developed in U1after filling. Having identified that indeed the combustible gas generation at 120ºC was higher for the oil in 50125, a pilot clay treatment was performed to determine if the contamination could be removed. The pilot clay treatment involved contacting the oil with attapulgite clay (Fuller s Earth) at a ratio of ¼ pound of clay to a gallon of oil at an elevated temperature to remove polar compounds that may have been present from contamination or aging byproducts. As shown in Table 10, the pilot clay processing was very successful in removing contamination that affected certain oil quality tests Table 10 Oil Quality Results Before and After Pilot Clay Treatment for Unit ASTM Test Units Prior to Clay Treatment After Clay Treatment Neutralization Number, D 974 mg KOH/g 0.01 <0.01 Interfacial Tension, D 971 mn/m Power Factor at 25 C, D 924 % Power Factor at 100 C, D 924 % The sample of the oil that went through pilot clay treatment was then again submitted for stray gas analysis. These results are presented in Table 11. As shown the pilot clay treatment completely changed the gassing profile. Table 11 DGA Results From Stray Gassing Investigation of Oil from U2 After Clay Treating, ppm v/v Gas Oil As Received Oil After Being Sparged with Nitrogen Oil After Aging at 120 C for 16 Hrs Oil after clay treatment and aging at 120 C for 16 Hrs Hydrogen Oxygen Nitrogen Methane Carbon Mon Ethane Carbon Diox Ethylene Acetylene TCG

10 CONLCUSIONS for Case 3 The oil as received was producing combustible gas in a transformer that was not even energized. Stray gassing results performed on the same oil indicated that indeed most of the gas formation was due to the oil. Other oil quality tests indicated that contamination occurred with polar compounds that could be removed by clay treatment. The clay treatment increased the IFT from 37 to 45 mn/m, reduced the power factor at 100 C from 1.011% to 0.100% and reduced the rate of combustible gas formation at low temperatures. The source of the contamination remains unknown but could have occurred in the tanker delivering the oil, any storage facilities used, or the oilprocessing trailer. In the end, it was decided to change out the oil instead of processing it, as they could not adequately determine the source of the problem. The gassing pattern for these units now appear normal [4]. Case 4: Conversion of Stable Sulfur Compounds Oil reclamation trailers that rejuvenate the clay (Fuller s earth) through heating have gained wide acceptance and have been used for a number of years with very good results [21]. They provide the benefit of reusing the clay multiple times before disposal. This is in contrast to the standard oil reclamation trailers that use towers of clay that have to be changed out and the material disposed almost every time processing occurs, which is expensive and more difficult in recent years. The issue with the in-situ clay rejuvenation occurred when it was determined that the oil exiting the trailer was more corrosive (corrosive sulfur) then the oil entering it and that it was blackening mainly the silver coated contacts in the transformer. Doble was employed to aid in the investigation of this phenomenon. In discussions with the utility it was determined that the clay was housed in multiple columns and that rejuvenating cycles inside the oil-processing trailer involved heating the clay to between 600 to 800 C for a period of 12 hours. For this particular design it was also noted that the oil storage chamber was only about an inch away with no insulation. Although, there would be some heat dissipation, it was theorized that the walls of the oil storage chamber were still extremely hot, probably in the vicinity of 200 to 400 C. A set of experiments were devised and performed to aid in understanding of what may occur to the oil subjected to this type of heating in terms of development of corrosive sulfur. In these experiments different products of Nynas brand oils were used as that was the common oil supplier in that region. Doble also used oils that were most likely available at the time the transformer was first installed. The oils were heated to a high temperature for the same amount of time as the heating of the clay in the process rig. The actual temperature of the oil in the chamber had not been measured so Doble decided on a temperature less than half the clay heating temperature and such that carbon would not be formed. Table 12 shows the Nynas products that were used in the experiments. Table 12 Oil Products Used for Testing Refiner Product Condition Age (Year Refined) Nynas Naphthenics, Sweden Nytro 10XN New 2006 Nynas Naphthenics, Sweden Nytro 10GBX New 2004 Nynas Naphthenics, Sweden Nytro 10GBXT New 2001 The experiments were conducted using the following parameters: Temperature: Initial Rate: 1.5 C/minute from ambient until it reached 275 C Aging Time: 12 hours at 275 C Oil Preparation: Sparged with nitrogen for 10 minutes Sample Vessels: 304 and 316 stainless steel vessels, sealed After aging was performed the oils were subjected to corrosive sulfur testing by ASTM Method D 1275B, the Doble CCD method, elemental sulfur analyis and dibenzyl disulfide (DBDS) analysis. The results of this testing is provided in Tables 2 through 4. 10

11 Results: The results of the experiments are provided in the Tables 13 through 15 below: Table 13 Results of the ASTM D 1275B Corrosive Sulfur Test After Heating 10 XN 10 GBX 10 GBXT Results Non-corrosive Corrosive Corrosive Tarnish Level 1b 4a 4b Picture The D 1275B test was carried out at 150 C for 48 hours. The Nynas oils 10 GBX and 10 GBXT both failed within 16 hours of the start of the test. In addition, copper sulfide flakes were already starting to fall off the copper coupon used with 10 GBXT. Table 14 Results of the Doble CCD Test After Heating Results 10 XN 10 GBX 10 GBXT Air Vial, paper Non-corrosive, medium dull Corrosive, metallic sheen Non-corrosive, medium dull Air Vial, Cu Rod Non-corrosive Corrosive Non-corrosive Air Vial, Cu Tarnish Level 3a 4a 3a Results 10 XN 10 GBX 10 GBXT Sealed Vial, paper Non-corrosive, light dull Corrosive, metallic sheen Corrosive, metallic sheen Sealed Vial, Cu Rod Non-corrosive Corrosive Corrosive Sealed Vial, Cu Tarnish Level 2e 4a 4a The ASTM D 1275B and Doble CCD tests provided information on whether or not the heating process would produce a reactive species but did not provide information on what type of corrosive sulfur was actually present. UOP Method 286 is a test method specifically for elemental or free sulfur. Other corrosive sulfur species may also be present such as DBDS. Tests for both these compounds were performed and provided in Table 15. Table 15 Results of the UOP 286 and the Doble DBDS Test, mg/kg After Heating Results 10 XN 10 GBX 10 GBXT Elemental Sulfur, Before Heating Cycle < 1 < 1 < 1 Elemental Sulfur, After Heating Cycle < Dibenzyl Disulfide, Before Heating Cycle < Dibenzyl Disulfide, After Heating Cycle < A standard of elemental sulfur in oil was prepared at 11 mg/kg (ppm). The UOP 286 analysis showed a concentration of 12 mg/kg so the accuracy of the UOP test was confirmed. Although there was a large amount of DBDS in two of the oils prior to heating, it was completely degraded in the heating and would not be the reason for the production of corrosive sulfur. The breakdown of DBDS or some other sulfur compound would be the reason for the production of elemental sulfur which is extremely corrosive even at low levels such as 1 or 2 ppm. 11

12 CONCLUSIONS for Case 4 Two of three Nynas branded oils (10 GBX and 10 GBXT) were adversely affected by heating at 275 C which caused the formation of elemental sulfur which is very corrosive. A small amount of DBDS was also present (1 mg/kg). Other corrosive sulfur compounds may have also existed but these could not be determined. It is therefore likely that given a specific oil with a similar sulfur species profile, that the oil processing trailer which heats the clay to rejuvenate it can cause the oil to become corrosive if the temperature is high enough and the duration long enough in the oil storage tank. As detailed in another paper [21] it does seem to be design dependent. Nynas Nytro 10 XN did not exhibit these same characteristics and is a much more stable product in terms of sulfur conversion to reactive species. Nynas oils were only used in this experiments as they were the products that this particular utiltiy was using. It is suspected that other oils might show similar characteristics and in testing of a Shell Diala D product similar results were obtained. Case 5: Using Laboratory Analysis to Determine Breaker Condition The Doble Engineering Laboratory had developed an oil breaker, oil test program a number of years ago [22] to allow the diagnostic condition assessment without being removed from service. Since that time many utilities have subscribed to this condition-based maintenance using diagnostic testing instead of time-based maintenance. Many thousands of breaker tanks have been tested using such programs, of which less than 1% required immediate attention, thus focusing attention on those units in need of service. This case study discusses a bank of breakers that required attention as discovered from the results of laboratory oil tests. The breaker information is as follows: Manufacturer: Federal Pacific Electric Manufacture Date: 1960 Model: RHE Rated Voltage: 121 kv Service Voltage: 115 kv Ampacity: 1200 amps continuous KA Rating: 26 Duty KA 24 Tanks: 3, Listed as Phases 1, 2 and 3 In order to provide a condition assessment for each OCB tank, a numeric ranking was determined. This numeric ranking was composed of a scaled assessment from four sets of analytical data: DGA, oil quality, particle count and metals. The numeric assessments from the four groups were summed. The points could range from From the points a ranking system was used to derive a Condition Code from which specific maintenance functions were recommended. The condition codes ranged from 1 to 5. A Condition Code of 1 indicates an OCB in the worst possible condition. A Condition Code of 5 would indicate a breaker in very good condition. A large emphasis is placed on the ethylene to acetylene ratios above certain levels, as it clearly distinguishes the severity of overheating conditions. In general, the gassing results and ratios were given more weight than the oil quality, particle count, or metal results as it tends to detect problems in the earlier stages, detects a wide range of problems and is the most reliable indicator [22]. Not all of the analytical data was used in the ranking and condition coding schemes even though it is used in the overall final condition assessment. For example, hydrogen and carbon monoxide were not used in the DGA ranking since they are easily lost to the atmosphere and changes in their concentration may be unduly influenced by sampling very close to a fault operation. Oxygen, nitrogen, and carbon dioxide represent atmospheric gases and were not included. However, in the final breaker assessment, oxygen and hydrogen levels are monitored to determine if the breaker breathing mechanism is plugged or some other unusual circumstance is occurring [22]. All the oil quality data and specific particle count data and ratios are used in the ranking scheme. There are exceptions however, for example the Doble Carbon Codes from the filter examination are not used in the rankings as 12

13 it is a simple numeric method of indicating how much carbon loading is present in a sample. Doble Carbon Codes are a series of increasing carbon levels ranging from 1 to 18, with a Doble Carbon Code of 1 having no carbon and a Doble Carbon Code of 18 being totally black with carbon [22]. The scheme for particles involves using a weighted ranking based on size of particles and ratios between different size classes. More emphasis was placed on the larger particles and their ratios to other classes as they are more likely to affect the operation of the breaker and as an indicator that breaker materials are disintegrating, thus having more significance. When ratios of different size classes are abnormal it may be directly related to accelerated degradation mechanisms [22]. The analysis of the metals can be very important as it provides indicators of excessive contact wear and component degradation. For example the presence and concentrations of silver, tungsten, and copper are weighed as important indicators of contact wear and severity. Other elements such as silicon can provide evidence for fiberglass component deterioration. The analytical results by group of this particular FPE breaker are provided in Tables 16 through 19. Table 16 DGA Analysis of Each Tank of FPE Breaker, ppm (v/v) Phase Hydrogen Oxygen Nitrogen Methane Carbon Monoxide Ethane Carbon Dioxide Ethylene Acetylene TCG Ratio ,700 64, ,600 61, ,000 61, The gassing pattern was very similar for all three phases. The oxygen and nitrogen values for each tank were satisfactory and indicated that the free breathing pipe was working properly and not clogged. Many of the other combustible gases were above the recommended limits and the ratio of ethylene to acetylene indicated thermal overheating of the contacts but was not yet indicative of thermal run away. Table 17 Oil Quality of Each Tank of FPE Breaker Phase D 974 Neut. No. mg KOH/g D-1816 kv Water Content ppm The oil quality was satisfactory for all three tanks except for the dielectric breakdown voltage of the oil in Phase 1. Table 18 Particle Count of Each Tank of FPE Breaker Phase Carbon > 100 Total Particles Code micron micron micron micron micron Per 10mL ,816 27, , , , ,116 32,559 10, ,407 Although it is expected that carbon will be manufactured during the arc quenching mechanism, certain criteria still apply. In all three phases, the overall amount of particles was excessive. Excessive carbon formation is usually a result of the breaker requiring more time to open than it normally would. The additional time causes more oil to be vaporized in the quenching activity. 13

14 Table 19 Metals Analysis of Each Tank of FPE Breaker, ppm (w/w) Phase Fe Cr Pb Cu Sn Al Ni Ag Mo Ti Si Zn W 1 ND ND 1 ND ND ND ND 5 ND ND 1 ND ND 2 ND ND ND ND ND ND ND 2 ND ND 3 ND ND 3 ND ND ND ND ND ND ND 4 ND ND 2 ND ND Key: Fe = Iron Al = Aluminum Si = Silicon Cr = Chromium Ni = Nickel Zn = Zinc Pb = Lead Ag = Silver W = Tungsten Cu = Copper Mo = Molybdenum Sn = Tin Ti = Titanium The metals were an important part of the diagnosis and were the final criteria that elevated the condition of all three tanks to be investigated immediately. From experience, it would take a lot of energy or mis-operation of the breaker to get silver to dissolve in the oil especially in the high concentrations shown for Phases 1 and 3. As a result, the calculated conditions codes were 1 for Phases 1 and 3 which recommended that the tanks be removed from service as soon as possible for investigation by thermography, electrical tests and/or internal inspection. The condition code for Phase 2 was 2 which indicated that the tank be immediately investigated as well, usually by thermography. As the result of the oil testing and a supervisor s gut feel, the tanks were removed from service for investigation. After the oil was drained, it was noted that there was excessive wear on the contacts and considerable erosion along the sides of the interrupter chamber. Electrical measurements showed that contact resistance was elevated in comparison to the last test made (800 to 860 micro-ohms versus 275 to 350 micro-ohms) and it was felt that the increase was due to erosion of the contacts and/or the stationary contact springs were weakened or out of adjustment. The breaker was also tested using a Doble TDR900 and revealed bouncing (chatter) of the A phase contacts during close operation and indicated that the contacts were not mating up properly during breaker close. Because of the age of the breaker, issues the utility had experienced with other of its type and the cost for the replacement of the interrupter shells (6 per phase), it was decided that the breaker would be maintained just enough to keep it operation until it was replaced 2 years later with an SF 6 breaker. CONCLUSIONS for this Case This case presented information on a condition assessment program for breakers that offers an analytical approach using DGA, particle counting and typing, oil quality and metals analyses. This type of diagnostic approach helps to quickly identify breakers that are in poor condition and then focuses attention to those breakers in a more timely fashion. It facilitates ranking of breakers as to condition so that a priority hierarchy can be established. In economic terms, condition based maintenance of oil circuit breakers makes practical sense. It focuses resources on intervention to prevent a breaker failure that can save a substantial amount of money not only in terms of replacement and installation costs but also in terms of lost revenue [22]. 14

15 Case 6: Failure of an O-ring Material Part of an o-ring was received in for testing. The material provided was left over from an o-ring that was used in a large power transformer manufactured in Brazil. The o-ring had failed only 5 months after the transformer had been installed and began to leak oil from the mating parts. The material provided is shown in Figure 2. Remnants of Transformer O-Ring Figure 2 Four different types of analysis were performed to aid in determining the cause of failure, Fourier Transformer Infrared (FT-IR), durometer (hardness), microscopic examination and SEM/EDX. The FT-IR was used to provide the general composition of the material. The analysis was conducted by pyrolyzing the gasket material on a KBr (potassium bromide) crystal. The samples was then analyzed through transmission FT- IR and scanned between 4000 and 5000 reciprocal centimeters. The spectrum of the samples was compared against a computer library and a match was made. The gasket sample was a positive match to Buna-N nitrile material (acrylonitrile butadiene rubber latex). The durometer measurement was made to determine if there was any difference between the outside of the gasket and inside of the gasket in terms of hardness. The results are shown in Table 20. Table 20 Durometer Measurements on Gasket Materials, Scale A Sample Durometer Range Inside of o-ring Material 68 to 71 Outside of o-ring material 57 to 70 Durometer Scale A ranges from 0 to 99. As the durometer increases so does the hardness of the material. In this case, areas inside the o-ring material were softer than areas on the outside. In addition, the wide range of durometer readings for the outside of the o-ring material is uncharacteristic and usual deviations observed are +/- 3 durometer points. Microscopic examinations revealed two separations of the top of the o-ring to about a depth of 1 mm running lengthwise. It did not reveal itself to be caused by mechanical means as there was no clear cut in the gasket and it appeared that the inner surface tried to re-heal with the outer surface. As there was very little insulating varnish 15

16 (glyptal) inside the crevices it seems to have happened after installation. In addition, white specks were found on the outside surface that were not readily identified. Additional analysis in the form of scanning electron microscopy/windowless energy dispersive x-ray analysis (SEM/WEDX) was performed on the o-ring sample. The o-ring was prepared for analysis by cleaning the outside surface with a sulfur-free hydrocarbon solvent. The gasket was then cut lengthwise to reveal the inside surface. The outside and inside surfaces of the o-ring were coated with evaporated graphite. The samples were then subjected to SEM/WEDX analysis in which an electron beam of the scanning electron microscope enters the bulk of a sample producing a x-ray emittance. The x-ray peak positions, along the energy scale, identify the elements present in the sample and can provide the percentage concentrations of each of these elements thus providing an elemental breakdown of the material or particles. The inside cut surface is shown in Figure 3. Cut Inside Surface of O-ring, 200X Magnification Figure 3 The cut surface in Figure 2 showed irregular striations, and pits. The EDX spectrum exhibited chlorine (~40.1%), zinc (~27.0%), sulfur (~23.6%), silicon (~7.2%) and calcium (~2.0%). The calcium content varied from none detected to a few percent and may have been related to the fine surface particles scattered on the surface. The WEDX spectrum exhibited moderate amounts of carbon, and a light amount of oxygen. The WEDX spectra for different areas on the cut inside surface of the o-ring are shown in Figure 4. Cut Inside Surface of O-ring, WEDX Spectra of 2 Different Areas Figure 4 The outside surface of the o-ring demonstrated an overall smooth surface with a parallel wavy appearance. There was some fine pitting present along with numerous surface blotches. The chemistry (exclusive of the surface 16

17 blotches) was qualitatively similar to the cut surface. The EDX spectrum consisted of chlorine (~48.1%), sulfur (~29.5%), zinc (~18.4%) and silicon (~4%). WEDX showed moderate carbon and a light amount of oxygen. A SEM photomicrograph of the surface is shown in Figure 5 and the WEDX spectra are shown in Figure 6. Outside Surface of O-ring, 200X Magnification Figure 5 Outside Surface of O-ring, WEDX Spectra of 2 Different Areas Figure 6 The surface stains (blotches) on the outside surface of the o-ring were examined in more detailed using SEM/WEDX. The blotches on the outside surface usually contained a contaminate particle at the center of the individual blotch. The chemistry of the blotches did differ from the normal surface. These blotches were composed of chlorine (~18.6%), silicon (~18.6%), iron (~17.1%), sulfur (~16%), zinc (~14%), magnesium (~11%), chromium (~4.1%) and calcium (~0.6%). The WEDX spectrum displayed a moderate concentration of carbon and light amount of oxygen. The contaminating particle in the center of the blotch usually was composed of magnesium and silicon (1:2 ratio), though a few particles were composed of just calcium or iron. Refer to Figures 7 and 8. 17

18 SEM Photomicrograph of Surface Stains (Blotches), 1000X Magnification Figure 7 WEDX Spectra of 2 Different Areas, Surface Blotches Figure 8 The last item of interest was a white precipitate that was noticed on the outside surface of the o-ring. A SEM photomicrograph of the material is shown in Figure 9. SEM Photomicrograph of White Precipitate on Outside Surface of O-ring, 1000X Magnification Figure 9 18

19 The white precipitate was composed of needle-like fibers. The chemistry was unusual since both EDX and WEDX results were extremely similar to the rubber gasket, even though the morphology was dissimilar. In fact, the interface area of the fibers suggested that the fibers were an etched portion of the rubber gasket. Refer to the EDX spectra in Figure 10. CONCLUSIONS for this Case WEDX Spectra of 2 Different Areas, White Precipitate Figure 10 The gasket material submitted for analysis was a positive match to Buna-N nitrile material (acrylonitrile butadiene rubber latex). Buna-N is a common material used for gasket material that is compatible to transformer oil up to a temperature of 120 C depending on the exact formulation. Although this material was Buna-N, the lower durometer measurements on the outside surface, the non-wear induced surface separations and the SEM/WEDX analysis indicate that some of the curing agent (sulfur compounds) may have been left behind and that portions of the gasket may not have properly cured. It was postulated that when the gasket was put into service, the un-cured portions especially those existing on the surface, resulted in the surface separations resulting in ultimate failure and resulting in oil leaks. Material compatibility experiments would have been useful in determining if this material was satisfactory for use prior to being applied in the transformer. More and more transformer manufacturers are relying on their suppliers to carry out this testing instead of doing it in-house and most utilities do not perform this testing on materials either. Secondary checks are good to make sure inferior materials are not being used out in the field for the cost of mitigating such situations can be quite extensive. ACKNOWLEDGEMENTS The authors would like to thank ESB International, Puget Sound Energy, Salt River Project and Tampa Electric Company for permitting the use of their information and laboratory testing results for some of the case studies provided in this paper. REFERENCES [1] Pugh, D., Advances in Fault Diagnosis by Combustible Gas Analysis, Minutes of the Forty-First International Annual Conference of Doble Clients, 1974, Sec [2] Baker, A. E. Gas Composition in Corona Discharge, Minutes of the Forty-Ninth Annual International Conference of Doble Clients, 1982, Section

20 [3] Duval, M., The Duval Triangle for LTCs, Alternative fluids and other applications, Proceedings of the Seventy-Sixth Annual International Conference of Doble Clients, 2009, Sec. IM-4 [4] Griffin, P. J., Lewand, L. R., Heywood, R., Lapworth, J., Gassing Characteristics of Transformer Oils at Modest Temperatures, Part 1: Transformer Experience, Proceedings of the Seventy-First Annual International Conference of Doble Clients, 2004, Sec. IM-3A [5] Griffin, P. J., Lewand, L. R., Heywood, R., Lapworth, J., Gassing Characteristics of Transformer Oils at Modest Temperatures, Part 2: Laboratory Experiments, Proceedings of the Seventy-First Annual International Conference of Doble Clients, 2004, Sec. IM-3B [6] Sheppard, H. R., The Mechanism of Gas Generation in Oil-Filled Transformers, Minutes of the Thirtieth Annual Conference of Doble Clients, 1963, Section [7] Christensen, P. and Ohlsson, G., The Behavior of Moisture and Free Water in Power Transformers, Proceedings of the Sixty-Fifth Annual International Conference of Doble Clients, 1998, Section 8-3 [8] The Doble Exchange, Vol. 11 #3, September 1993, pg. 4-5 [9] Oommen, T. V., Girgis, R. S., and Ronnau, R. A., Hydrogen Generation from Some Oil-immersed Cores of large Power Transformers, Proceedings of the Sixty-Fifth Annual International Conference of Doble Clients, 1998, Sec. 8-8 [10] Shirai, M., Ishii, T., and Makino Y., "Evolution of Hydrogen from Insulating Oil," IEEE Trans. Elec. Insulation. Vol. EI-2, No. 4, August 1977, pp [11] Doble Insulating Materials Report, Spring 2004, pg. 4 [12] Hughes, B. R., Moore, H., Analysis of Gases in a Large GSU and Special operating Guidelines for a Family of Large Westinghouse Transformers, Manufactured Without Insulated T-Beams Generating High Levels of Combustible Gases, Proceedings of the Sixty-Third International Conference of Doble Clients, 1996 Sec, 8-11 [13] Griffin, P. J. Discussion of the B. Hughes and H. Moore Paper, Analysis of Gases in a Large GSU and Special operating Guidelines for a Family of Large Westinghouse Transformers, Manufactured Without Insulated T-Beams Generating High Levels of Combustible Gases, Proceedings of the Sixty-Third International Conference of Doble Clients, 1996 Sec, 8-11B [14] Nakahito, K., Recent Activities on Maintenance Management for Power Transformers, Proceedings of the Seventy-Fourth Annual International Conference of Doble Clients, 2007, Presentation only [15] Doble Transformer Oil Purchase Specifications (TOPS), Doble Engineering Company, Watertown, MA USA, 2008 [16] IEEE C57.106, IEEE Guide for the Acceptance and Maintenance of Insulating Oil in Equipment, IEEE, 2002 [17] Doble Oil Survey Report 95, Doble Engineering Company, Watertown, MA USA, 2002 [18] Griffn, P. J., Gassing Characteristics of New Oils Used in Factory Heat Runs, Doble Oil Committee Minutes, 1994, pg [19] CIGRE TF11 B39, Gas formation tendency test for mineral transformer oils, CIGRE,

21 [20] ASTM D 7150, Standard Test Method for Determination of Gassing Characteristics of Insulating Liquids of Thermal Stress at Low Temperature, in Annual Book of ASTM Standards, Volume 10.03, Electrical Insulating Liquids and Gases, 2005 [21] Dahlund, M., Johansson, H., Lager, U., and Wilson, G., Understanding the Presence of Corrosive Sulfur in Previously Non-Corrosive Oils Following Regeneration, Proceedings of the Seventy-Seventh Annual International Conference of Doble Clients, Boston, MA, Insulating Materials Session, IM-5, 2010 [22] Lewand, L.R., and Bordash, W., Using Insulating Liquid Analysis by DBA to Diagnose Oil Circuit Breaker Condition, Proceedings of the Seventieth Annual International Conference of Doble Clients, Boston, MA, Insulating Materials Session, 2003 AUTHOR BIOGRAPHIES Lance R. Lewand Lance Lewand is the Director of the Doble Insulating Materials Laboraotory and is also the Product Manager for the Doble DOMINO, a moisture-in-oil sensor. The Materials Laboratory is responsible for routine and investigative analyses of liquid and solid dielectrics for electric apparatus. Since joining Doble in 1992, Mr. Lewand has published over 50 technical papers pertaining to testing and sampling of electrical insulating materials and laboratory diagnostics. Mr. Lewand was formerly Manager of Transformer Fluid Test Laboratory and PCB and Oil Field Services at MET Electrical Testing Company in Baltimore, MD for seven years. His years of field service experience in this capacity provide a unique perspective, coupling laboratory analysis and field service work. Mr. Lewand received his bachelor of science degree from St. Mary's College of Maryland. He is actively involved in professional organizations the American Chemical Society, representative of the U.S. National Committee for TC10 of the International Electrotechnical Commission (IEC), and ASTM D-27 since 1989 and is the subcommittee chair 06 on Chemical Tests. He is also the secretary of the Doble Committee on Insulating Materials. Paul J. Griffin Mr. Griffin has been with Doble since 1979 and held the position of Laboratory Manager before becoming Vice President of Laboratory Services. Since joining Doble, Mr. Griffin has published over 60 technical papers pertaining to testing of electrical insulating materials and laboratory diagnostics. He is a Fellow of ASTM and a member of Committee D-27 on Electrical Insulating Liquids and Gases. He was formerly ASTM Subcommittee Chairman on Physical Test, ASTM Section Chairman on Gases in Oil, and the Technical Advisor to the U.S. National Committee for participation in the International Electrotechnical Commission, Technical Committee 10, Fluids for Electrotechnical Applications. Mr. Griffin is a member of the IEEE Insulating Fluid Subcommittee of the Transformer Committee, and the American Chemical Society. 21