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The first two articles can be read directly on this page by clicking on the titles below. You may also read/save the articles by selecting the Adobe pdf Reader or Microsoft Word Icons to the right of each article. If you do not have Adobe pdf reader, it is available as a free download here.

The Phenomena of Moisture in Transformer Oil
New, re-fined or refurbished Mineral Oil Techon 2007

Field Trial of Vacuum Dry-out System
Tapchanger Trial

The Phenomena of Moisture in Transformer Oil Water in oil appears as an unwanted substance, it is generally accepted that water in microscopic amounts - not gallons- is the cause of more electrical breakdowns than any other impurity.  Moisture constitutes a hazard not only to the insulating qualities of the oil but also to the insulations that are immersed in the oil. Water may be introduced to the oil by leaking gaskets, poor handling techniques or from the product of natural insulating paper and oil degradation.  As the paper degrades, it produces Carbon Dioxide and Water and as the insulating oil ages, water, acids, sludge and other polar compounds are formed.  So its presence is inevitable during the normal service life of a transformer. Water is a polar liquid having a high permittivity or dielectric constant it is therefore attracted to areas of strong electric fields.  This sees the internal moisture distributed not uniformly, but in fact potentially concentrating in the most dangerous parts of the system. It is important to note that water is in a continuous state of movement between the oil and paper insulating system, caused by internal temperature variations due to load and ambient conditions. Water may be present in four possible forms, they are:             •  Free water – That is water that has settled out of the oil in a separate layer.  It is this water which is indicated by a low dielectric breakdown voltage.             •  Emulsified water – Or water that is suspended and has not yet settled out into free water (indicated by “caramel” coloured oil). Nb: A high Power Factor value indicates the possible presence of this suspended water trapped in oil decay products.             •  Water in solution – or dissolved in the oil.             •  Chemically bound water – Water which is chemically attached to the insulating paper and which is released when oxidized. The destructive effects of water include:             •  Expansion of the paper insulation, altering the mechanical pressure of the transformer clamping system.             •  Loss of insulating ability (Dielectric Breakdown Voltage)             •  Accelerating paper aging ie triggering decomposition of the fibres in the paper             •  Increased corrosion of the core and tank             •  Progressive consumption of oil additives The most dangerous and destructive of these effects is the loss of the oils insulating ability.  This may occur from the following events:             •  During periods of high load and at high ambient temperatures, dielectric breakdowns can result from the reduced oil strength with high absolute amounts of water.             •  With sudden high loads, water can boil off conductor surfaces and the vapour bubbles can cause dielectric failures as they rise to the top.             •  During the cool-down period after high load, the relative saturation of oil will increase.  At its extreme at 100% relative saturation, water will precipitate out and greatly reduce the dielectric strength of the oil. If oil is oxidized to any extent, any water coming into the transformer will partially be absorbed into the oil decay products (It is this fact which causes old or highly oxidised oil to dissolve more water than new oil).  As the decay products build up in the oil, the surface tension of the water or the interfacial tension between the oil and the water is lowered dramatically.  This heavier decay molecule will then recirculate throughout the entire transformer and will find its way into the paper insulation, or into areas of high electrical intensity thus reducing the insulation resistance. The water saturated oil decay molecule has a preference for the coolest part of the transformer (bottom and fins, leading to corrosion) and areas of highest electrical stress (leading to arcing). It has been proven that insulating paper with 2% moisture content ages three times faster than one with 1% moisture and thirty times faster with 3% moisture. It is thus easy to see the importance of maintaining low moisture levels within a transformer to ensure a long and trouble free service life.

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TECHCON 2007 PANEL DISCUSSION “New, re-refined or refurbished? Options for mineral oil”     Is there any such thing as new mineral oil? Take the carcasses of a few million dinosaurs, a few hundred hectares of trees and sub-vegetation, bury them under hundreds of meters of mud and sludge for a thousand years or so and you have ‘new’ oil. Put it though a refining process and it is readily accepted by engineers everywhere.      Once that same oil has been in service for 20 or 30 years then passed through a passive microscopic filtration process to remove all contaminants and many of the same engineers refuse to consider its use. Why? Most common answer is, “we don’t want second hand oil in our equipment”. Surely that is an emotive response more suited to the ‘arts sector’ than practical, fact based engineering types?        In this brief presentation I hope I can help dismiss some of the myths, cut through some of the sales talk and hopefully begin an objective thinking process in most of you. Firstly;  What is Oil Refurbishment?      Refurbishment of oil has been carried out using adsorption by Fullers Earth for decades and is often still used as the final stage in oil refining or re-refining. Adsorption is the tendency of a liquid, gas or small particle to cling to the surface of another substance by physical rather than chemical means.      Fullers Earth is a hydrated magnesium and aluminum silicate with a unique crystalline structure. Once activated through high temperature, this clay possesses up to 13 hectares of surface area per kilo. Most of the contaminants found in serviced oil are polar in nature and are therefore easily adsorbed by the Fullers Earth.      When coupled with fine particulate filters (<0.5 micron) plus a high vacuum degasser/dryer system, virtually all oxidation by-products can be removed and the oil returned to original, new oil specifications. The Refurbishment process also removes corrosive sulfur and metals from the oil.      Once the natural inhibitors consumed in the oxidation process have been replaced by a synthetic anti-oxidant, usually 2,6 Di-tert-butyl-4-Methylphenol (also called DBPC and BHT), the refurbished oil is often more stable than new oil.           Table 1 Oil Analysis of Refurbishment by Fluidex Fullers Earth treatment process 400kV Transformer, National Grid Company,UK Test Before Process After Refurbishment After 1 Year Operation After 2 Years Operation Moisture ppm 23 8 10 11 Acidity mgKOH/gm 0.20 <0.01 0.01 0.02 Dielectric kV 35 76 71 69 Sludge content % 0.02 <0.01 <0.01 <0.01 Resistivity at 90C 2.5 226 184 160 DDF at 90C 0.095 0.005 0.006 0.009 Oxidation Stability Total Acid mg KOH/g sludge% by mass 0.48 2.29 0.16 1.23 0.18 1.30 0.19 1.32 Viscosity at 40C 11.9 11.8 11.8 11.6 Interfacial Tension 25 40 38 36 Aromatic Carbon 10 10 Paraffinic Carbon 48 48 Napthenic Carbon 42 42 Sulphur Content % 0.333 0.320 0.321 Corrosive Sulphur Positive negative negative negative Phosphorus ppm 11 ND ND ND Zinc ppm 3 ND ND ND  Does Refurbished oil meet the same specifications as new oil? Table 2 Test Parameter Test Method Refurbished Oil ESI Bulk Tank New Oil Specification Pass/Fail Moisture (ppm) D1533 10 <30 Pass Dielectric BV (kV) IEC156 85 >60 Pass Acid Number (mgKOH/gm) D974 0.01 <0.03 Pass Interfacial Tension (mN/m) D971 42.7 >40 Pass Dielectric Dissipation Factor (% at 25C) IEC247 0.011 0.05 Pass    Does Refurbished Oil last in service? Table 3 Case History – In-situ Oil Refurbishment 1978 10MVA 33/6.6kV Wilson Transformer, Serial no. 60580 Date Acidity mgKOH/gm IFT Dynes/cm DDF % at 25C Inhibitor % 10/11/1992 0.180 19.4 13/10/1993 0.180 19.0 ++ 29/10/1994 0.020 43.1 0.002 20/1/1996 0.020 42.2 0.080 0.49 28/8/1996 0.020 39.1 0.062 0.43 8/1/1998 0.020 39.9 0.082 0.48 ** 7/12/1998 0.020 33.0 0.041 0.48 11/1/2000 0.030 32.6 0.080 0.32 ** 18/1/2001 0.010 37.8 0.021 0.40 23/11/2002 0.010 37.0 0.027 0.40 21/1/2004 0.010 36.6 0.028 0.40 28/1/2005 0.020 36.7 0.053 0.42 30/1/2006 <0.010 37.2 0.035 0.38 9/2/2007 0.020 36.0 0.033 0.48  ++ In-situ oil reclamation carried out * * Change in testing facility  How does in-situ oil refurbishment compare with retro-filling the unit with new oil? Table 4 Case History – Retro-fill and In-situ Oil Refurbishment * 5MVA GE Transformer Serial No.7935639 Date Treatment Acidity mgKOH/gm IFT Dynes/cm July 1966 0.40 15 July 1967 0.42 14.5 July 1967 Retro-filled with new oil 0.03 41 Sept 1968 0.12 24 Sep 1968 In-situ Oil Refurbishment 0.03 40 Mar 1970 0.045 36 Feb 1971 0.045 30 Mar 1972 0.05 32 Feb 1973 0.055 30 Feb 1974 0.06 32.5 Jan 1975 0.05 32 Jan 1976 0.055 32 Feb 1977 0.05 31.5 The oil test history detailed in Table 4 illustrates a major difference in the actual in-field performance following retro-filling and in-situ oil refurbishment. There are two major factors are involved in the poor performance of New Oil following retro-filling. Retro-filling a transformer will not remove sludge deposits from the core, windings, radiators, and floor of the transformer. A thorough flushing can only remove 10 to 15% of the sludge deposits within a transformer. As soon as the transformer is re-filled and energized, the sludge deposits begin to contaminate the new oil and degradation occurs very quickly. Even in sludge-free transformers, the cellulose insulation and spacers retain approximately 10% of the total oil volume within the unit. This cannot be drained out and will begin to contaminate the new oil as soon as the unit is re-filled.          In-situ Oil Refurbishment gives a vastly superior performance mainly because during refurbishment, hot clean oil is circulated through the transformer, between 6 and 16 passes, depending on the severity of the sludging. The clean oil is returned to the top of the transformer above the aniline point for transformer oil, which is the point at which the oil will dissolve its own oxidation by-products. The dissolved sludge is then drawn into the refurbishment plant, via the main tank drain valve, and removed by the activated Fullers Earth filter media. This not only removes surface contamination but begins to clean deposits embedded in the cellulose, particularly the outer insulation layers.      Typically a Fullers Earth Refurbishment plant will produce twice the daily volume of refurbished oil in a ‘tank to tank’ situation (where input and finished product oil specifications are similar) compared to in-situ transformer work. This is due to the extra time and adsorption required to dissolve and remove contaminates from the within the transformer.       A decrease in Transformer Top Oil Temperatures of 8 degreeC has been observed in transformers following in-situ oil refurbishment due to the removal of sludge deposits. I suggest this is mainly due to the removal of sludge in the radiators. The actual decrease in ‘Hot Spot Winding Temperature’ is likely to be closer to twice this value as similar sludge deposits also blanket the core and block cooling ducts. A reduction in operating temperature of 8 degreeC will double the life expectancy of a transformer.    Graph 1 Life Expectancy with Variable Oxygen and Temperature Lampe, Spicer and Carrander Study -1977

Temperature degree C (End of Life Definition – DP = 200)     Insulation and Power Factor testing carried out on transformers before and after In-situ Refurbishment show significant improvements can be achieved through this process. This is mainly due to the removal of moisture from cellulose insulation during the refurbishment process but testing also indicates a reduction in other contaminants in the solid insulation.        Is ‘Super Refining’ really so Super?   Over the last 20 years almost all the transformer oil brought into Australia and New Zealand has come from the same Venezuela crude oil base. Notable exceptions were the High voltage DC link Transformers New Zealand inter-island and Australia Bass link.     When the Venezuela crude was first introduced the most notable difference was the higher aromatic content compared with previous oils. Whether this is totally because of the base oil or the newer refining techniques (Hydrogenation) is unclear, but Transpower (NZ) had to adjust their new oil acceptance criteria, which specified a maximum of 10% aromatics, to cater for the new oil which had a typical aromatic content of 14%. From a service provider’s point of view, the biggest difference we noticed was that, even with a very low moisture content, this oil produced a lot more foam in the high vacuum degassing chamber during processing. Our conclusion was that the oil contained a lot more light ends which boiled off under vacuum.         Hydrogenation, as used in modern refining and re-refining plants, uses hydrogen on a catalytic surface to chemically convert unwanted molecules into desired ones. The severity, temperature, pressure and velocity can all be controlled to produce the desired output. These parameters must be set by skilled chemists who have a full understanding of both the input oil and the service requirements of the product. Once the parameters are correctly established, in large scale plants with constant base oil as the input, the product from there-on should only vary slightly over time. In smaller plants, with variable input oil specifications, I suspect consistency in output very much depends on the skill and knowledge of the operators and chemists involved.     Refurbishment plants using Fullers Earth, do not have this problem, the refurbishment process simply extracts unwanted compounds, rather than attempting to convert them into desired ones. The worst that can happen is that a small percentage of the un-wanted compounds remain in the oil after processing. This process is therefore much more suited to field use or where the input stock is variable.           What about chemical reactions within the transformer?     Some have described an energized transformer as a huge chemical reactor. Not only is Iron, Copper, Paper, Solvents, Moisture, Oxygen and other compounds linked by fluid (Oil), electrical stress, leakage currents and magnetic fields are there to mix it all up. In recent times a number of failures have occurred in transformers due to corrosive sulphur reacting with copper conductors, forming metal sulfides in the paper insulation. Since the metal sulfides are conductive, the dielectric breakdown strength of the paper is reduced leading to breakdown between conductor strands on a disk or between disks. This has ultimately caused the failure of some major assets including a 500 kV shunt reactor and a 450 MVA auto transformer. The following graph illustrates the effect of adding paper covered and bare copper to an oil oxidation test.      The Sulphur present in transformer oil depends on the original crude oil used and on the degree and method of refinement. This Sulphur is normally stable and actually improves the oxidation stability of the oil. It appears however that under high levels of stress, high temperature plus electrical stress, the sulphur can become corrosive and lead to chemical reaction with copper described. The Effect of Copper as a Catalyst in Oil Oxidation

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