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5. TRANSFORMER OIL
For both the designer and the user of an oil-filled transformer it can be of value to have some understanding of the composition and the properties of the transformer oil and an appreciation of the ways in which these enable it to perform its dual functions of providing cooling and insulation within the transformer.
Such an understanding can greatly assist in obtaining optimum performance from the transformer throughout its operating life.
That is the main purpose of this section. To increase awareness of the role of insulating oil, which can often be taken somewhat for granted and to help those having dealings with oil-filled transformers to recognize the important part which the oil plays in the achievement of satisfactory operation.
Since this is intended to be an electrical engineering textbook it is not the intention to go too deeply into the chemistry of insulating oils. It has already proved necessary to look a little at the chemistry of cellulose in order to under stand something about the properties of paper insulation. It is even more the case that some understanding of the chemistry of transformer oil can be of value to transformer designers and users. In fact, it is not possible for engineers to get the best from any material, particularly one as complex as insulating oil, without some understanding of its chemistry.
Much of today’s industrial technology involves an appreciation of many aspects of science. Electrical power engineers often find that they have a need to call upon the knowledge of physicists, chemists and materials scientists, but each of these specialists brings their own viewpoint to the solution of a problem, often without appreciating the true nature of the problem faced by the user of the equipment, and it is left to the engineer to understand and interpret the advice of these specialists to obtain an optimum and economic solution.
This is particularly true with insulating oil. So much so that many engineers with years of experience do not have a full understanding of the subject, and many chemists with a very detailed knowledge of the chemistry cannot translate this knowledge into practical advice of use to the operator of the plant.
The statement has already been made that transformer oil has a dual role.
It is appropriate to look a little more closely at each of these aspects.
Oil as a coolant
In discussion of the other basic materials, iron and copper, mention has already been made of the energy losses which their use entails. These, of course, manifest themselves in the form of heat. This results in a rise in temperature of the system, be it core and windings, core-frames, tank or other ancillary parts.
These will reach an equilibrium when the heat is being taken away as fast as it is being produced. For the great majority of transformers, this limiting tempera ture is set by the use of paper insulation, which, if it is to have an acceptable working life, must be limited to somewhere in the region of 100ºC. Efficient cooling is therefore essential, and for all but the smallest transformers, this is best provided by a liquid.
For most transformers mineral oil is the most efficient medium for absorbing heat from the core and the windings and transmitting it, sometimes aided by forced circulation, to the naturally or artificially cooled outer surfaces of the transformer. The heat capacity, or specific heat, and the thermal conductivity of the oil have an important influence on the rate of heat transfer.
Oil as an insulator
In most electrical equipment there are a number of different parts at different electrical potentials and there is a need to insulate these from each other. If this equipment is to be made as economically as possible the separation between these different parts must be reduced as much as possible, which means that the equipment must be able to operate at as high an electrical stress as possible. In addition, transformers are often required to operate for short periods above their rated voltage or to withstand system transients due to switching or to lightning surges.
The oil is also required to make an important contribution to the efficiency of the solid insulation by penetrating into and filling the spaces between layers of wound insulation and by impregnating, after they have been dried and de-aerated by exposure to vacuum, paper and other cellulose based insulation material.
As an indication of the importance that is placed on electrical strength, it should be noted that for a long time, since the early days of oil-filled transformers, a test of electrical strength was the sole indicator of its electrical quality. Even today when there are many more sophisticated tests, the electrical withstand test is still regarded as the most simple and convenient test for carrying out in the field.
Viscosity and pour point
Heat can be dissipated in three ways, by radiation, by conduction and by convection, and each of these contributes to cooling the core and conductors of an oil filled transformer, but convection is by far the most important element.
This convection relies upon the 'natural circulation' produced by gravity due to the difference in density between the hotter and the cooler fluid. The ease with which this convection flow can be induced clearly is very dependent on the viscosity of the fluid and it is therefore important for a transformer oil to have a low viscosity. Sometimes the convection is forced or assisted by means of pumps, but it is still desirable that the need for this assistance is minimized by the use of an oil which itself offers the minimum resistance and maximum convective assistance to the flow.
Additionally, low viscosity will assist in the penetration of oil into narrow ducts and assist in the circulation through windings to prevent local overheating which would result from poorer flow rates in the less accessible areas.
Initial impregnation is also greatly accelerated by the use of oil which is thin enough to penetrate into multilayers of paper insulation found in areas of high stress in extra-high-voltage transformers.
Mineral oils, like most other fluids, increase in viscosity as their temperature is reduced until they become semi-solid, at which stage their cooling efficiency is virtually nil. The pour point of a fluid is the lowest temperature at which the fluid is capable of any observable flow. For many transformers used in cold climates the oil must not approach this semi-solid condition at the lowest temperatures likely to be experienced and so the oil must have a low pour point.
Even at temperatures which, though low, are well above this pour point, the viscosity of the oil must be such that the flow is not significantly impeded.
Specifications for transformer oil thus frequently specify a maximum viscosity at a temperature well below the normal ambient.
Volatility and flash point
Normally transformers are expected to have a life of at least 30 years. It is desirable not to have to constantly think of making good evaporation losses during this lifetime, nor is it acceptable that the composition of the oil should change due to loss of its more volatile elements. Low volatility is therefore a desirable feature.
It will be recognized that fire and explosion are to some extent potential risks whenever petroleum oils are used in electrical equipment. It is therefore necessary that the temperature of the oil in service should be very much lower than the flash point. On the other hand it is possible for oil to become contaminated by more volatile products which even when present in quite small quantities may constitute an explosion hazard when the oil is heated in normal service.
Such contamination has been known to occur due to removing oil from a transformer in service and transferring it to drums or tankers which had previously contained a volatile solvent.
Certain types of electrical fault can also give rise to comparatively volatile lower molecular weight hydrocarbons or to inflammable gases due to break down of the heavier constituent molecules of the transformer oil.
All petroleum oils are subject to attack by oxygen in the atmosphere.
Transformer oil is no exception although the extent to which this takes place depends on many factors.
The subject of oxidation, the reasons why it is important to prevent this and the ways in which this can be achieved will be discussed at some length later in this section. Selectivity in the types of oil, or more precisely, the constituents of the oil that is used and control of the factors which affect oxidation are the most effective strategies. Three factors are most evident: temperature, availability of oxygen and the presence of catalysts.
Oils consisting of high molecular weight hydrocarbon molecules can suffer degradation due to decomposition of these molecules into lighter more volatile fractions. This process is also accelerated by temperature. It is desirable that it should not occur at all within the normal operating temperatures reached by the plant, but it cannot be prevented at the higher temperatures generated by fault conditions. This aspect will be discussed at some length in Section 6.7.
Selection of oils: the refining process
So far the main properties which are required from an electrical oil have been identified. There are other less important properties which, if it were possible, it would be desirable to influence. These will be discussed when oil specifications are examined in detail. If the properties that have been identified above could be closely controlled, this would go a long way to producing an electrical oil which would meet most of the needs of the practical engineer.
Types of oil
Petroleum oils have been used in electrical equipment since the latter part of the last century. Sebastian de Ferranti, who might be considered to have been the father of the transformer, recognized their benefits as long ago as 1891.
Their performance has been improved a little since then, both as a result of better refining techniques and in the way in which they are selected and used. They still represent a very important component of much electrical power plant.
Firstly, it is appropriate to look a little at the sources and production of oil.
All types of mineral oils are obtained from crude petroleum, which is said to have been formed from buried and decayed vegetable matter or by the action of water on metal carbides. It is defined by the American Society for Testing and Materials, ASTM. D288 as follows:
A naturally occurring mixture, consisting predominantly of hydrocarbons which is removed from the earth in liquid state or is capable of being removed. Crude petroleum is commonly accompanied by varying quantities of extraneous substances such as water, inorganic matter and gas. The removal of such extraneous substances alone does not change the status of the mixture as crude petroleum. If such removal appreciably affects the composition of the oil mixture then the resulting product is no longer crude petroleum.
Crude petroleum is now extracted from the earth in many parts of the world and its quality and composition vary within quite small geographical areas.
It is a complex mixture of molecules made up of carbon and hydrogen and a small proportion of sulphur and nitrogen.
There are three main groups of hydrocarbon molecules. These are paraffins, napthenes and aromatics. Each has a characteristic molecular structure, and no two crudes are exactly alike in the relative proportions of the hydrocarbon types or in the proportions and properties of the products to which they give rise.
FIG. 21 shows the typical molecular structure of the three types of hydro carbon, and includes some of the simplest members of the groups. The simplest paraffin is methane, CH4, a gas, but there is almost no limit to the length of the straight chain of carbon atoms, or to the variety of paraffins with branched chains, the iso-paraffins, with side chains attached to individual carbon atoms in the main chain. Normal butane, C4H10, is shown as a straight chain paraffin, while isobutane, also C4H10, has a single branch, and both occur in petroleum gas, but some idea of the complexity of the mixtures of compounds that petroleum represents can be gauged from the fact that there are more than 300 000 possible iso-paraffins all with the basic formula C20H42, and many billions with the formula C40H82.
The napthenes have ring structures and those shown in Fig. 21 have six membered rings, that is, rings with six carbon atoms though, it will be noted, the three-ring compound has 14, not 18, carbon atoms. Napthenes with five- or seven-membered rings also occur in petroleum but six-membered are the most common. The aromatics, too, have six-membered ring structures, but with the important difference that some of the carbon atoms are joined by double bonds, shown in the figure as double lines. This has the effect of making the aromatics 'unsaturated' and, in general, more reactive. Aromatics fall into two groups, those with single rings or monoaromatics, and those with two or more rings or polyaromatics, sometimes termed PACs. In petroleum based transformer and switch oils the aromatics vary in proportion, but are generally present in much smaller amounts than either the napthenes or the paraffins.
Many classifications have been proposed for the various types of crudes, but the most generally accepted is that based on the main constituent of the distillation residue and consists of four descriptions: paraffinic, asphaltic, mixed or intermediate, and napthenic. The world's known supply of crude oil is made up of very approximately 7 percent paraffinic, 18 percent asphaltic (including 5 percent napthenic) and 75 percent mixed or intermediate.
In the UK for at least 60 years, insulating oils have been manufactured almost exclusively from napthenic or intermediate crudes, at one time from Russia and more recently from Venezuela, Peru, Nigeria and the Gulf Coast of the USA.
Refining of petroleum
Crude oil is subjected to a series of physical and chemical treatments to pro duce the refined product. A typical refinery is custom designed to deal with a particular type of crude oil and to produce a selected range of products. The development of cracking, reforming and hydrofining processes in recent years has revolutionized the petroleum industry, and has resulted in the production of finished products which are 'tailor made' and which bear no relation to the crude oil feedstock composition. Thus, the classification given to the crude oil may no longer have the same significance in relation to the end product.
In a typical refinery which produces a full range of products the crude oil is distilled at atmospheric pressure to remove the low boiling point products, and these are then used as fuels and solvents after suitable further refining. The residue may then be distilled under vacuum to give stocks for the production of electrical and lubricating oils. The residue from this vacuum distillation can then be used for the production of fuels, asphalts and bitumens depending on the quality of the feedstock and the product(s) required.
The vacuum unit distillate is refined by one or more of a number of processes such as: selective solvent extraction, sulphuric acid extraction, earth filtration, hydrogenation, re-distillation, filtration and dehydration. The most economical technique is used, subject to the processes available at the refinery, which will produce a product to the required quality level. The aims of the refining processes are to remove or reduce waxes, sulphur, nitrogen, and oxy gen-containing compounds and aromatic hydrocarbons.
Alternative viscosity grades are obtained by suitable blending of the distillate fractions collected or by re-distillation in the case of a single fraction.
In principle, solvent refining relies upon the selective solubility of such materials as wax, sulphur and nitrogen compounds and aromatic hydrocarbons in the selected solvents; sulphuric acid chemically combines with sulphur compounds and aromatic hydrocarbons; earth filtration removes residual polar contaminants; and hydrogenation reduces sulphur, nitrogen and aromatic hydro carbon compounds.
Earth filtration is nowadays regarded as rather environmentally unfriendly in view of the large quantity of contaminated filtration medium which it produces and which it is required to dispose of. For this reason the process is now less frequently used but it is still without equal in the production of the highest quality electrical oils.
Hydrogenation is the most recent and versatile refining treatment and the reactions are controlled by temperature, pressure, catalyst, time and other factors. Light hydrogenation, usually referred to as 'hydrofinishing' or 'hydropolishing,' may be used following one or more of the other processes to remove sulphur and nitrogen by converting the compounds to hydrocarbons. Severe hydrogenation, also called 'hydrofining,' is used to reduce the total unsaturated ring compounds; for example, aromatic to napthene and paraffin hydrocarbons, when those compounds containing the highest number of rings react first.
In producing electrical oils particular attention is paid to producing the required electrical properties, oxidation stability and, where appropriate, gas absorbing properties. (Good gas absorption is a requirement particularly called for in oil for power cables.) This necessitates low sulphur and nitrogen con tent, but an optimum aromatic content. FIG. 22 shows the effects of refining treatment on the principal properties of insulating oil.
viscosity, density and refractive index
aromatics, sulphur and nitrogen
A little more about the classification of oils
Mention has already been made of the extent and complexity of the array of hydrocarbons which go to make up a particular crude oil. Such complexity makes it difficult to describe and classify oil from a particular source. One way of getting round this, the Brandes system, which uses infrared spectroscopy, is to express hydrocarbon content in terms of the total carbon in the individual types of hydrocarbon irrespective of whether it is present as an individual compound or as a substituent group attached to a type of hydrocarbon. Thus, it is possible to express percentage carbon in paraffin chains %CP, percentage carbon in aromatic rings %CA and percentage carbon in napthene rings %CN.
It is of interest, using this classification to look at a number of crudes which have been traditionally classified as either napthenic or paraffinic. These are listed in Table 3.
Table 3 Typical analyses of crude oils classified as naphthenic and paraffinic showing actual pro portions of aromatics, naphthenes and paraffins present
It will be noted that in no fewer than four of the so-called napthenic oils, the percentages of carbon atoms in paraffinic structures are markedly higher than in napthenic structures, and in two others the proportions of the two types are very similar. Among the paraffinic oils, the paraffinic structures predominated, but the %CP values for two of them were almost identical to those of the napthenic oils. The essential difference between the two types of oil seems therefore, less one of differing %CP/%CN relationships or structural constitution but the fact that the paraffinics contain wax whereas the normally selected napthenic crudes contain little or none. The significance of this fact will be explained later.
Specification of insulating oil
Towards the beginning of this section certain properties for insulating oil were identified as being very important. These are:
• Low viscosity
• Low pour point
• High flash point
• Excellent chemical stability
• High electrical strength
There are also some other properties which might be less important, but for which it would nonetheless be desirable to have some say in their determination. These include:
• High specific heat
• High thermal conductivity
• Good impulse strength
• High or low permittivity, depending on intended use
• High or low gas absorbing, depending on intended use
• Low solvent power
• Low density
• Good arc quenching properties
And, of course, in addition to all of the above it is required that the insulating oil be cheap and easily available!
It is clear that no single liquid possesses all of these properties and that some of the requirements are conflicting. Compromise, therefore, will be necessary and the design of the equipment will have to take into account the shortcomings of the oil.
It is appropriate to look at how these properties are specified and at the tests made for them according to EN 60296:2004. The UK continues to remain out of step with most of the world so that the BS states that EN 60296 should be read in conjunction with BS 148:1998. This is mainly based on the continuing preference in the UK to use uninhibited oil, unlike most other parts of the world which uses oil with inhibitors. More will be said about this aspect later.
BS 148:1998 also included for the first time a specification for oxidation inhibited oil, although little use is made of such material in the UK. Its use is widespread however in most other parts of the world and so the subject of oxidation inhibited oils will be considered at some length later in this section. However, for clarity, in the present context only uninhibited oil will be considered.
The following characteristics are laid down in BS 148:1998 for uninhibited oils:
Physical properties of transformer oil
In the foregoing specification the properties concerned with the physical nature of the oil are viscosity, closed flash point, pour point and density. The first three of these are properties which were identified as falling within the 'important' category. The reason for specifying closed, as opposed to open flash point, is that the former is more precise and more meaningful than the latter. The fire point is normally approximately 10ºC higher than the closed flash point. The reason for the three classes, I, II and III, is concerned with the use of insulating oil in switchgear as well as the provision of oils for use in very cold climates.
This aspect will be discussed in a little more detail shortly.
Viscosity is measured in glass tube viscometers, which can be closely standardized and also allow the use of the centistoke or mm2 /s, which is based on the absolute definition of viscosity. In the specification, the temperatures of measurement indicated for viscosity are _15ºC, for Class I oil, and 40ºC. For Class II and Class III oils the low-temperature points are respectively _45ºC and _60ºC. FIG. 23 shows the extent to which the three grades of oil com plying with the requirements of IEC 60296 vary in viscosity with temperature.
With increases in temperature, the viscosity of oil falls, at a rate dependent upon its particular chemical composition. An unacceptably high viscosity at low temperatures is guarded against by the specification of a maximum viscosity limit at the lower temperature, _15ºC in the case of Class I oil and correspondingly lower for Classes II and III. The document does not lay down a lower limit for viscosity because the specification of a minimum for closed flash point prevents the use of the lowest viscosity fraction of the oils. Similarly, because the specification stipulates a maximum value for viscosity, the closed flash point of transformer oil cannot be very much above the minimum requirement stated.
It is left to the oil refiner's skills and experience to give due regard to all these points in selecting the base oil for the manufacture of the transformer oil so that the best compromise can be obtained. One of the important requirements of the oil used in switchgear is that it must assist in the quenching of the arc formed by the opening of a circuit breaker. This necessitates that the oil must quickly flow into the gap left by the separating circuit breaker contacts, which demands that it must have low viscosity and which is the other main reason for the specification of Class II and III oils. For these low viscosity is more important than high flash point which explains why it is necessary to relax the requirement in respect of this parameter.
Closed flash point
The reason for wishing to fix the closed flash point is, as mentioned above, to ensure that some of the coolant is not lost over the years. Loss would be greatest in the case of distribution transformers without conservators. These present the largest oil surface area to the atmosphere. They are, of course, the transformers which it would be most preferable to install and forget, but if they experience loss of oil there could be a danger of getting into the situation where ultimately windings are uncovered.
The closed flash point of oil is measured by means of the Pensky-Martens apparatus. It gives a guide to the temperature of the oil at which the combustible vapor in a confined space above it accumulates sufficiently to 'flash' upon exposure to a flame or other equivalent source of ignition.
The value of _30ºC for the maximum pour point of Class I oil is used in many specifications, since this represents a likely minimum ambient tempera ture in which electrical plant might be called upon to operate. The inclusion of Classes II and III oils with pour points of _45 and _60ºC respectively is specifically to allow for oils for use in very cold climates.
The reason for wishing to place a limit on density is because at very low temperatures the increase in density might be such that ice, if present, would float on the top of the oil. The density limit of 0.895 g/cm^3 (max) at 20ºC ensures that the temperature must fall to about _20ºC before the density of oil, of the maximum permitted density at 20ºC, would exceed that of ice. Clearly, if there is to be ice, it is preferable for it to form at the bottom of the tank, out of harms way.
Chemical properties of transformer oil
Some description has been given of the chemical composition of oil, and mention has been made of the need for chemical stability, that is, resistance to oxidation and decomposition. The former requirement is covered in the BS 148 Specification by the specifying of limiting values for sludge formation and acidity, which, as will be shown later, are closely linked to oxidation.
In Section 6.7, the subject of decomposition of transformer oil will be discussed at some length and it will be seen that the decomposition process is much the same for all types of electrical oils. This is probably the reason why BS 148 does not address this aspect of chemical stability.
In fact, the other chemical properties that BS 148 seeks to define are those which ensure freedom from small amounts of undesirable compounds, demonstrated by low initial acidity and freedom from corrosive sulphur.
Resistance to oxidation
Sludge deposition and increase in acidity are both linked to the oxidation pro cess. Earlier specifications did not recognize this, neither did they recognize the harmful effects of high acidity. BS 148:1923 included an oxidation test with a limit to the amount of sludge produced. However new oil was allowed an acidity equivalent to 2.0 mg K OH/g, a figure which is 4 times higher than the level at which oil would now be discarded.
The current BS 148 oxidation test is carried out by maintaining a sample of 25 g of the oil in the presence of metallic copper--copper is a powerful catalyst for oxidation--at 100ºC whilst oxygen is bubbled through the sample for 164 hours. The oil is then cooled in the dark for 1 hour, diluted with normal heptane and allowed to stand for 24 hours, during which time the more highly oxidized products are precipitated as sludge, which is separated and weighed. The remaining solution of n-heptane is used for the measurement of acidity development. The combined two values effectively define the oxidation stability of the oil.
Acidity as supplied
The initial acidity, or acidity as supplied, as distinct from acidity after the oxidation test, is considered by some no longer to be a test of quality since, in the course of normal refining, it is possible to reduce the acidity to a negligible level. It does, however, represent a test of quality to the extent that it demonstrates freedom from contamination. The specification recognizes that it is difficult to obtain complete freedom, but nevertheless sets a very low level of 0.03 mgKOH/g. The acidic materials which may contaminate the oil are not capable of precise definition but may range from the so-called napthenic acids, which are present in unrefined petroleum, to organic acids which are formed by oxidation during the refining process.
At this point it may be appropriate to consider the method used for quantitative estimation of acidity. Most of the standards covering electrical oils express acidity in milligrams of potassium hydroxide required to neutralize 1 gm of oil (mgKOH/g). The method of establishing this is by titration of the oil with a standard solution of the alkali in the presence of a suitable solvent for acids.
Such a method is described in BS 2000: Part 1, the point of neutralization being shown by the colour change of an added indicator, this being an organic material of a type which experiences a colour change on becoming alkaline.
Test for corrosive sulphur
The test for corrosive sulphur, sometimes known as deleterious sulphur and copper discoloration, was made more severe with the issue of BS 148:1972. It involves immersing a strip of polished copper in oil at a temperature of 140ºC and in an atmosphere of nitrogen for 19 hours, after which the copper is examined. An oil is failed if the copper strip, or part of it, is dark grey, dark brown or black. A pass does not necessarily mean that the oil is free from sulphur com pounds but simply that these are not of an active nature. At this point, in the previous edition of this work, the statement was made that with modern transformer oils trouble in service due to sulphur attack on copper is, nowadays, very rare indeed. Around the year 2000, however, problems in transformers due to corrosive sulphur have re-emerged and there have been a number of major failures reported due to this cause such that a need has been seen to carry out further research and to frame a more rigorous test for the presence of sulphur in oil. More will be said on this subject in Section 6.7.
Although this does not truly represent a chemical property, it is convenient to include the test for water content with the chemical tests.
Water is soluble in transformer oil only to a limited extent. The solubility ranges from about 30 to 80 ppm at 20ºC, with the higher levels of solubility being associated with the higher aromatic content oils. The solubility is higher at higher temperatures.
The presence of free water will reduce the electrical strength of oil. Whilst it remains dissolved, the water has little detrimental effect on the oil, but it is the case that paper insulation has a very great affinity for water, its equilibrium level in contact with oil being such that the quantity contained in the paper is very much greater than that in the oil. The main objective, therefore, in striving to obtain low moisture-in-oil contents, is in order to limit the quantity of water in the paper insulation. The subject of water in oil will be discussed at some length later in this section.
Traditionally the test for free water has been the crackle test. A small quantity of the oil is heated quickly in a shallow cup over a silent flame. The object is to heat up the water to well above its normal boiling point before it can dissolve in the hotter oil. As the water droplets instantaneously expand to become vapor they produce an audible crackle.
The 1972 issue of BS 148 introduced the Karl Fischer method detailed in BS 2511 for the first time. The test is a complex one but it is claimed to have a repeatability to approximately 2 ppm. In the 1984 issue this is retained but the acceptable levels are reduced slightly.
Electrical properties of transformer oil
The electrical strength test included in all BS Specifications prior to BS 148:1972 is very much seen as the fundamental test of the oil as an insulant. It is not surprising to learn that it was, in fact, one of the earliest tests devised on transformer oil. It is nevertheless not truly a test of the electrical quality of the oil so much as an assessment of its condition. In first class condition the oil will withstand an electrical stress very much higher than that demanded by the standard. However, very small traces of certain impurities, namely moisture and fiber, particularly in combination, will greatly reduce the withstand strength of the oil.
As originally devised, the electrical strength test involved the application of the test voltage to a sample of oil contained in the test cell across a pair of spherical electrodes 4 mm apart. The sample was required to withstand the specified voltage for 1 minute, any transient discharges which did not develop into an arc being ignored. A pass required two out of three samples to resist breakdown for 1 minute.
The issue of BS 148:1972 replaced the above test by one which measures breakdown voltage and this is retained in the 1984 and 1998 issues. In this test oil is subjected to a steadily increasing alternating voltage until breakdown occurs. The breakdown voltage is the voltage reached at the time that the first spark between the electrodes occurs whether it be transient or total. The test is carried out 6 times on the same cell filling, and the electric strength of the oil is the average of the six breakdown values obtained. The electrodes have a spacing of 2.5 mm. The electrodes of either copper, brass, bronze or stainless steel are either spherical and 12.5-13 mm in diameter or spherical surfaced and of dimensions shown in Fig. 24.
The first application of the voltage is made as quickly as possible after the cell has been filled, provided that there are no air bubbles in the oil, and no later than 10 minutes after filling. After each breakdown, the oil is gently stirred between the electrodes with a clean, dry, glass rod; care being taken to avoid as far as possible the production of air bubbles. For the five remaining tests the voltage is reapplied 1 minute after the disappearance of any air bubbles that may have been formed. If observation of the disappearance of air bubbles is not possible it is necessary to wait 5 minutes before a new breakdown test is commenced.
The minima for breakdown voltage in the post-1972 issues of BS 148 are lower than those of earlier issues. This does not, of course, represent a lowering of standards, but simply reflects the new method of carrying out the test - and especially the fact that the gap between the electrodes has been reduced from 4 to 2.5 mm.
DDF and Resistivity
Dielectric dissipation factor (DDF) which used to be known as loss angle or tan d, and resistivity are more fundamental electrical properties than electrical strength and are of most interest to designers of EHV transformers.
Only DDF is considered as mandatory by BS 148:1998, however reference to resistivity remains in BS 5730:2001 as an indication of electrical quality especially for used oils. This latter document is discussed further in Section 6.7. For DDF measurement a specially designed test cell or capacitor is filled with the oil under test which displaces air as the capacitor dielectric. The cell is connected in the circuit of a suitable AC bridge where its dielectric losses are directly compared with those of a low-loss reference capacitor.
The cell employed should be robust and have low loss; it must be easy to clean, reassemble and fill, without significantly changing the relative position of the electrodes. The diagram, Fig. 25, shows two possible arrangements.
The upper one is recommended by CIGRE (Conference Internationale des Grandes Réseaux Electriques), and consists of a three-terminal cell which is now widely used. An alternating current bridge (40-62 Hz) is used, which should be capable of measuring loss angle or tan d down to 1 _ 10_4 for normal applications, but preferably down to 1 x 10^-5 , with a resolution of 1 x 10^-5 in a capacitance of 100 pF. The voltage applied during the measurement must be sinusoidal. Measurement is made at a stress of 0.5_1.0 kV/mm at 90ºC, and is started when the inner electrode attains a temperature within _0.5ºC of the desired test temperature.
For DC resistivity measurement, the current flowing between the electrodes is measured when a specified voltage, normally 550 V, is applied to the cell.
The current is noted after the voltage has been applied for 1 minute. The electrodes should be short circuited for 5 minutes between the DDF and resistivity measurements. Average resistivity values are calculated from readings taken after direct and reverse polarity. For measurement, an instrument capable of detecting 10_11 A is required.
More closely standardized methods for both DDF and resistivity have also been published as BS 5737:1979 which aim to provide greater precision.
Additives and inhibited oil
In the oil industry in recent years, particularly for oils used for lubrication, enormous advances, providing spectacular improvements in performance, have been made by the use of oil additives, that is, very small quantities of substances not naturally present in oil which modify the performance or properties of the oil.
Similar results are possible in the field of electrical oils, although the transformer industry, particularly in the UK, has been cautious and reluctant to accept this.
This caution has mainly been concerned with how long the beneficial effects are likely to last. After all, even with the benefits of the most modern additives it is not yet possible to leave the oil in a motor car engine for 30 years! There has also been some suspicion on the part of users that, by the use of additives, oil companies might seek to off-load onto the transformer industry, oils which have been under-refined or are not entirely suitable for the electrical industry.
Reasons for additives
Before discussion of the additives themselves and the properties which it might be desirable to gain from them, it is logical to consider the undesirable properties of oils and what can be done to minimize the problems which these cause without the resort to additives.
It has already been highlighted that electrical oil is subject to oxidation and that this leads to sludge formation. Perhaps 30 or more years ago, when a transformer was taken out of service, either due to old age or because of premature failure, it was often the case that the complete core and coils were covered by heavy, dark brown, sludge deposits. These deposits partially block ducts, reducing the oil circulation. They reduce the heat transfer efficiency between the coils and the core steel and the oil. This, in turn, causes copper and iron temperatures to rise, which, of course, further increases oxidation and sludge formation, and so the problem becomes an accelerating one. Excessive temperatures lead to more rapid degradation of insulation and the transformer may fail prematurely.
As already indicated, another result of oxidation is the increase in acidity of the oil. At one time this acidity was seen as less of a problem than that of sludge formation, and, indeed, that is probably the case. It is now recognized, however, that increased acidity of the oil is very detrimental to the well being of the transformer, and therefore something to be avoided. The acids are organic and nothing like as corrosive as, say, sulphuric acid, but they can cause corrosion and accelerate the degradation of solid insulation.
There is, however, a great deal which can be done to reduce oxidation with out the use of additives.
Firstly by reducing the degree of contact between the oil and air. There are good reasons for not wishing to seal off the oil completely from the external air and these will be identified later. However, in all but the smallest distribution transformers it is economic to provide a conservator. Not only does this reduce the area of contact between the oil and air, but it also ensures that the oil which is in contact with air is at a lower temperature than the bulk oil.
Temperature is, of course, an important factor. Each 7ºC increase in temperature above normal ambients doubles the rate of oxidation.
Then there are, as has been mentioned, the effects of catalysts. It is unfortunate that copper is a strong catalyst in the oxidation process. Iron is a catalyst also, but not quite so strongly. There is little that can be done about the copper in the windings, although being insulated does restrict the access to the oil thereby reducing the effect. Bare copper, such as is frequently used for lower voltage leads and connections can be tinned, since tin does not have a catalytic action.
The internal surfaces of steel tanks and steel core frames can be painted with oil-resistant paint.
There is also an effect which is sometimes referred to as auto-catalytic action. Some of the products of oxidation themselves have the effect of accelerating further oxidation. This is particularly the case when some aromatic compounds are oxidized. Hence, oils with increased aromatic content over a certain optimum quantity of about 5-10 percent are more prone to oxidation. The curve, Fig. 26, shows the effect of varying aromatic content on oxidation.
By the use of these measures alone there has been a significant reduction in the extent to which oxidation has shown itself to be a problem over the last 30 or so years. Offset against this is the fact that since the 1970s there has been a tendency to increase operating temperatures, and measures to reduce the degree of contact between the oil and catalytic copper and iron have been reduced as a cost saving measure, particularly in many distribution transformers, it is possible that once again users will begin to experience the re-emergence of oxidation as a serious problem in many transformers.
Use of additives
In the UK it has been the practice not to allow additives in electrical oil.
Elsewhere additives have been used in transformer oils for many years with the specific purpose of inhibiting oxidation. In fact, oils thus treated were referred to as inhibited oils.
Inhibition of oxidation is achieved by the inclusion of oxidation inhibitors, metal passivators and deactivators. The latter react with metals to prevent the metal catalysis mechanism, whilst oxidation inhibitors react with the initiation products, free radicals or peroxides to terminate or break the oxidation reactions.
Some naturally occurring oil compounds, principally those containing sulphur, act as oxidation inhibitors in this way. As a result of research into the oxidation process it became clear that certain organo-metallic compounds of copper, when dissolved in the oil, were even more active catalysts than the oil itself. Certain compounds were then developed which deactivate or 'passivate' the copper surfaces essentially preventing solution of copper in the oil, and even inhibiting the catalytic effects of any existing copper in solution.
Most transformer engineers are now familiar with inhibited oils but their use is still frowned upon in the UK. In addition to the natural suspicions on the part of the users, this is probably due to the quality of the uninhibited oils which have been available for many years, coupled with the increased care with which they are maintained, resulting in such long life in most transformers that users have been reluctant to meet the higher first cost that inhibited oil involves.
The 1972 edition of BS 148 stated 'the oil shall be pure hydrocarbon mineral oil … without additives. By arrangement between seller and buyer the oil may contain an oxidation inhibitor or other additive, in which case the oil, before inclusion of the additive, shall comply with the BS. Oils complying with the requirements of this standard are considered to be compatible with one another and can be mixed in any proportion; this does not necessarily apply to inhibited oils.' The insertion of this clause had two objectives:
(1) To allay fears about the use of under-refined or unsuitable base oils, as mentioned previously.
(2) To ensure as far as possible that oils, after possible loss of inhibitor in service, would not be prone to unduly rapid deterioration, as might be the case if the base oils were not of the best modern type.
However, oxidation inhibited oils tend to be popular in most of Europe as well as in the USA, and as already discussed, BS 148:1998 has a section covering inhibited oils. The reason for its inclusion in the BS specification, however, is regarded by most UK users of transformer oil as solely for the purposes of European Harmonization.
Of course, the technical possibilities of inhibited oils are most important in applications where the operating temperature of the oil may be higher than average, such as could be the case in tropical locations, but due regard must be paid still to the effect of such temperatures on cellulose insulation.
Pour point depressants
The only other additives in common use in transformer oil are as pour point depressants. Their use is more recent than oxidation inhibitors, dating back to about the 1970s. It will be recalled that BS 148 requires that oil should be fluid down to a temperature of _30ºC. This level of performance is available from naphthenic oil so there was little need to seek any measures to obtain an improvement. However, it seemed, in the early 1970s, that the world's supply of naphthenic crudes might be very close to running out (this has since proved to be far from the case). In addition, there were other economic reasons for wishing to produce electrical oils based on paraffinic crudes. These oils do not exhibit the low pour points shown by the naphthenic based oils due to the tendency of the waxy paraffinic constituents to solidify at relatively high temperatures. Although as already mentioned de-waxing is possible and can form part of the refining process, this is costly and therefore defeating the objective of the use of paraffinic crudes.
Pour point depressants work by preventing the wax particles precipitated out at low temperatures conglomerating and forming a matrix and impeding the flow of the oil.
It is interesting to note that initially naphthenic oils were thought not to contain many paraffinic hydrocarbons, but, as indicated in Table 3.3 it is now known that this is not the case and that many naphthenic oils have as high a %CP as do the paraffins. What appears to be the case is that the paraffinic hydrocarbons in these oils are of a 'non-waxy' type.
Miscibility of oils
It is important to look briefly at miscibility of oils. This is unlikely to be a problem in the UK with only a small number of suppliers of exclusively uninhibited oils, all of which can and frequently are mixed. It is also the case that most users in the field will recognize the wisdom of avoiding the mixing of different types and grades of oil, but in many parts of the world it might be more difficult to achieve such an ideal in practice and a greater awareness is therefore necessary.
Before giving the following guidance it is necessary to remind the reader that wherever possible the oil supplier should be consulted and the above comments are not intended to contradict any guidance which the oil supplier might provide.
Firstly, most manufacturers of oils claim that mixing of paraffinic and naphthenic is permissible, even assuming the paraffinic oil might contain additives in the form of pour point depressants, and they have evidence, from field trials, in support of this.
It should be recognized, of course, that it is the refiners of the paraffinic oils who have an interest in getting into the market, who are keen to allow mixing of oils, and it is usually they who, therefore, carry out the field trials. The problems can arise when a manufacturer of naphthenic oil is asked to remove the oil from a transformer to which paraffinic has been added. He, arguably justifiably, may not wish his bulk stock to become contaminated with additives over which he has no control even though he is simply taking it for re-refining.
The problems are similar with inhibited oil. If the inhibited oil complied with BS 148:1972, or a similar standard which required that the quality of the oil before addition of inhibitors was as good as the uninhibited oil, then mixing simply dilutes the inhibitors, which, by definition, are not necessary any way, and so the mixture is acceptable. The difficulty is when a manufacturer is asked to recover oil which has an unknown composition. Such action should not therefore be viewed as routine, but preferably one to be undertaken only in an emergency.
Mixing of different refiner's brands of inhibited oil demands very much greater caution. The compatibility of different additives is not known and much more likely to cause problems. BS 148:1984 advises that if mixing of inhibited oils is contemplated 'a check should be made to ensure that the mixture complies with the requirements of this standard.' To carry out such a check properly would be a time-consuming exercise and would hardly be justified simply for the purposes of topping-up existing equipment with oil from an inappropriate source.
Water in oil
Theory of processes
Water, of course, is not an additive. In fact, it would be convenient if it were not present at all, but a discussion of water probably follows naturally from a discussion of additives, in that it is the other major non-hydrocarbon which is always present in the oil.
The point has already been made that the presence of some water in the oil, provided it remains in solution, does not greatly affect the electrical strength of the oil. However, water in paper insulation does significantly reduce its electrical insulation properties.
Oil in contact with air of higher humidity will absorb moisture and carry it across to the paper insulation. This action is also reversible of course, which is the principle that is employed when aiming to dry out the insulation of a transformer in service, but it can be a time-consuming process to reverse an action which may have been occurring for many years. The water distributes itself between the air, oil and paper so that the relative saturation is the same in each medium when equilibrium is reached. The solubility of water in oil varies with the type of oil from approximately 30-80 ppm at 20ºC, with the higher levels being associated with the higher aromatic oils. Water solubility also increases with ageing (oxidation) of the oil.
The effect of temperature on solubility is very marked. FIG. 27 shows a typical relationship. From the curve it can be seen that an oil which might be fully saturated with 40 ppm of water at 20ºC will hold around 400 ppm at 80ºC. This demonstrates why it is important to record the temperature of the oil when drawing a sample for assessment purposes. A water content of 50 ppm in a sample drawn from a newly filled unit at 20ºC would give cause for concern, but the same figure in a sample taken from an old unit at 80ºC would be very good indeed because it would represent a much lower level of saturation, as can be seen from Fig. 28.
It has already been identified that the water distributes itself between air, oil and paper in accordance with the relative saturation level in each medium. Paper, however, has a much greater capacity for water than does oil. Its saturation level can be 5 percent or more by weight depending on the temperature and the acidity of the oil. A large 600 MVA generator transformer could contain 10 tonnes of cellulose insulation and with a water content at, say, 2% would contain as much as 200 liters of water in the insulation. This explains why attempting to dry out the insulation on site by circulating and drying the oil is such a slow and laborious process. More will be said about the subject of drying-out on site in Section 5.4.
For some years it has been known that the presence of moisture in the solid insulation accelerates the ageing process. It is only relatively recently, how ever, that the extent to which this is the case has been clearly recognized, probably as a result of the research effort which has been put into the subject following many premature failures of large extra-high-voltage transformers.
The life of paper insulation at 120ºC is reduced by a factor of 10 by increasing the moisture level from 0.1 percent to 1 percent. The latter figure, which was considered a reasonably acceptable moisture level a few years ago, represents no more than about 20 percent of the saturation level for the paper. Thus it can be clearly seen that it is desirable to maintain the level of water in oil as far as possible below its saturation level and that a figure of around 30-40 ppm of water in oil at 80ºC is a reasonable target.
Considerable research effort is still being expended on the subject of water in oil, which reveals that the interaction is a complex one. Much of the foregoing comments relating to oil/water properties have assumed equilibrium but of course, equilibrium is very unlikely to exist in a transformer in service. Load and ambients, for a start, are constantly subject to variation. For a more detailed treatment of the subject the reader is referred to several papers reporting work carried out by V.G. Davydov et al. at Monash University in Australia.
Transformer breathing systems
Because of the high thermal expansion of transformer oil, it is necessary, for all but the smallest transformers, to provide a mechanism to accommodate this expansion.
Mention has already been made that there would be merit in excluding air from transformer oil. This would greatly reduce the oxidation problem. Indeed there are some users who do this, particularly in tropical climates with pro longed periods of high humidity. They specify that the transformer be pro vided with a membrane or diaphragm system which allows for expansion and contraction of the oil without actually allowing this to come into contact with the external air. Such users generally also experience high ambient temperatures which aggravate the oxidation problem.
The disadvantage of the sealed system, though, is that water is a product of the degradation process of both oil and insulation. By sealing the transformer this water is being sealed inside the transformer unless a procedure of periodic routine dry-outs is adopted. If a free-breathing system is provided and the air space above the oil is kept dry by the use of a de-hydrating breather, then these degradation products will be able to migrate to the atmosphere as they are produced and, of course, their continuous removal in this way is far easier than allowing them to accumulate for periodic removal by oil processing.
An improvement over the type of de-hydrating breather which uses a chemical desiccant is the refrigeration breather which relies on the Peltier effect to provide freeze drying for the air in the conservator over the oil. In fact, this air will circulate, via reverse convection, through the refrigeration device, whether the transformer is breathing or not, so that this air, and hence the oil and the insulation, are being continually dried in service. Because of their cost, refrigeration breathers can only be justified for large EHV transformers, but they probably represent the optimum available system. Refrigeration breathers are used on all transformers connected to the UK 400 and 275 kV grid systems.
Oil preservation equipment will be considered further in Section 4.
Maintenance of transformer oil in service is discussed in Section 6.7.
Other dielectric liquids
There are some locations where the flammable nature of mineral oil prevents the installation of transformers filled with it. From the early 1930s askarels, synthetic liquids based on PCBs have been used to meet such restrictions on the use of transformer oil. However, due to the non-biodegradable nature of PCBs, which cause them to remain in the environment and ultimately to enter the food chain, plus their close association with a more hazardous material, dioxin, production of these liquids has now ceased in many countries and their use is being phased out.
Alternative insulants such as silicone liquids and synthetic ester fluids possessing high flash points, good thermal conductivities and low viscosities at low temperatures are now in worldwide use. This combination of properties renders them acceptable to the designers and manufacturers of fire-resistant transformers and there has been an increasing market for this type as the use of askarel is diminishing. Generally these transformers have been built to conventional designs developed for mineral oil or askarel with very little modification. The liquids themselves are capable of satisfactory operation at temperatures above that appropriate for mineral oil, but there are problems if attempts are made to take advantage of this. Firstly and most significantly it is necessary to find an alternative to paper insulation, and secondly, high operating temperature tends to equate to high current density which results in high load losses increasing operating costs and offsetting any savings made in initial cost.
A number of specialist organizations exist who have developed the skills for draining askarel-filled transformers, refilling them with alternative liquids and safely disposing of the askarels. The process is however fraught with difficulties as legislation is introduced in many countries requiring that fluids containing progressively lower and lower levels of PCBs be considered as and handled as PCBs. It is very difficult as well as costly to remove all traces of PCB from a transformer. This persists in insulation, in interstices between conductors and between core plates so that some time after retrofilling, the PCB level in the retrofill fluid will rise to an unacceptable level. The result is that retrofilling is tending to become a far less viable option, and those considering the problem of what to do with a PCB-filled transformer are strongly encouraged to scrap it in a safe manner and replace it.
Silicone liquid, a Dow Corning product, is frequently employed in transformers where there is a desire to avoid fire hazard. Silicone liquids are synthetic materials, the most well known being polydimethylsiloxane, characterized by thermal stability and chemical inertness. They have found a wide range of practical applications and have an acceptable health record over many years use in medical, cosmetic and similar applications.
Silicone liquid has a very high flash point and in a tank below 350ºC will not burn even when its surface is subjected to a flame. If made to burn it gives off very much less heat than organic liquids, having a low heat of combustion and the unique property of forming a layer of silica on the surface which greatly restricts the availability of air to its surface.
Distribution transformers using silicone liquid have been in operation for several years and there are now several thousand in service. The ratings of these transformers lie mainly in the 250 kVA to 3 MVA, 11 to 36 kV working range, but units up to 9 MVA at 66 kV have been manufactured.
Synthetic ester fluid
Complex esters or hindered esters are already widely accepted in the fields of high temperature lubrication and hydraulics, particularly in gas turbine applications and as heat transfer fluids generally. In this respect they have largely replaced petroleum and many synthetic oils which have proved unstable or toxic.
A similar ester has been developed to meet high-voltage insulation fluid specifications and is finding increasing application as a dielectric fluid in transformers and tapchangers.
Midel 7131 transformer fluid developed in the UK by Micanite and Insulators Limited is a synthetic ester which has a very high flash point of 310ºC and an auto-ignition temperature of 435ºC. Synthetic esters also possess excellent lubrication properties, which enables the fluid to be used with forced cooled (i.e. pumped) units of all types.
Midel 7131 is manufactured from compounds which can be largely vegetable in origin and it has proved to be of very low toxicity; in certain cases it has been shown to be many times less toxic than highly refined petroleum oil, and being completely biodegradable is harmless to marine life.
Although the physical properties of synthetic ester fluids made them possibly the best dielectric liquids in situations for which fire safety was an important consideration, their high cost relative to other available fluids has tended to restrict their widespread adoption. Since the late 1990s a natural ester based dielectric has become available which is considerably less costly and has the added advantage that, like the synthetic esters, it is entirely biodegradable. The fluid was developed by Cooper Power Systems in the USA and by 2006 had gained its most widespread use in the USA where it goes under the trade name Envirotemp FR3. The fluid is manufactured from vegetable seed oils to which it no doubt owes its biodegradability. It is entirely non-toxic. Envirotemp is also finding application in Europe, and at the time of writing, in early 2007, two 90 MVA, 132 kV, units with on-load tapchangers have been manufactured in the UK for evaluation in service on the distribution network.
Envirotemp has a fire point of 360ºC and flash point of 330ºC, which gives it the highest ignition resistance of the currently available less-flammable fluids.
The fluid is entirely compatible with insulation materials and other components normally used in transformer manufacture. It has an excellent chemical stability with time. Dielectric properties are good enough to permit its use in sectionalizing and load-break switches. It is compatible with mineral oil and is therefore useable as a retro-filling fluid for oil-filled transformers. However, if used in this way, it must be recognized that the presence of quite modest quantities of lower fire point fluids will impair the fire performance of any mixture.
The fluid has low viscosity, comparable to mineral oil and its cooling performance is claimed to be better than other less-flammable fluids. It has a high affinity for water and its saturation level for dissolved water is considerably higher than that of mineral oil. The manufacturers claim this feature as an advantage and say that if Envirotemp FR3 is used to retrofill a transformer whose insulation has a high moisture content, its capacity to absorb water will have a drying effect on the paper. The manufacturers also claim that the effect of this is to inhibit breakdown of the chain molecules of paper insulation and thus help extend transformer life.
On the debit side, Envirotemp has a poor oxidation stability and will oxidize quite rapidly at normal handling temperatures. For this reason it is imperative that transformers filled with the fluid should not be free breathing but must have a diaphragm type seal. The oxidation tendency is particularly strong when the fluid is in the thin film state, so that the 'repack' process, used by most manufacturers, for which they remove the newly processed active parts from their tank to enable windings, cleats and the like to be tightened to take up any shrinkage resulting from impregnation and dry-out, must be completed as rapidly as possible to limit exposure to air. Oxidation results in the formation of a 'skin' on the surface in contact with air due to the formation of long-chain polymers from the oxidized ester molecules. If oxidation takes place, these long-chain molecules remain in the fluid and result in increased viscosity and impaired cooling flow.
The standing period following vacuum filling of a transformer must be slightly longer than for mineral oil since air bubbles are slightly slower to disperse.
Envirotemp can be sampled for condition monitoring purposes in much the same way as for mineral oil, except that discharges produce less hydrocarbon gas than for mineral oil whilst excess thermal stress results in greater quantity of gas.
Envirotemp FR3 is not compatible with silicone based fluids.
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4. Roizman, O., Davydov, V.G. and Ward, B. (2000) 'Water-in-paper activity: a new approach for moisture management in transformers.' EPRI Substation Equipment Diagnostics Conference XIII.
5. Oommen, T.V., Claiborne, C.C., Walsh, E.J., and Baker, J.P. (2000) 'A new vegetable oil based transformer fluid: development and verification,' IEEE Conference on Electrical Insulation and Dielectric Phenomena, Vancouver, BC, pp. 308-312.