TRANSFORMER OIL HANDBOOK
www.nynas.com/naphthenics
TRANSFORMER OIL HANDBOOK
CONTENTS INTRODUCTION 1
HANDLING AND STORAGE
1.1 1.2 1.3 1.3.1 1.3.2 1.3.3 1.3.4 1.4 1.4.1 1.4.2 1.4.3 1.4.4
General Storage in tanks Choice of vessels Transport in ships Transport in road tankers, railcars and containers Transport in “Flexi-bags” (rubber bags) Transport in drums Contaminants – and possible corrective measures Water Particles Chemical contamination Base oils/solvents
2
MAINTENANCE OF TRANSFORMER OILS IN SERVICE
2.1 2.2 2.3 2.3.1 2.3.2 2.3.3 2.3.4 2.3.5 2.3.6 2.4 2.5 2.6 2.6.1 2.6.2
General Sampling What to analyse and why Colour and appearance AC-breakdown voltage Water content Neutralization value Dielectric dissipation factor and/or DC-resistivity Interfacial tension Filling a transformer with new oil Frequency of oil testing Other analyses to evaluate transformer status Gas-in-oil analysis and furfuraldehyde content Polychlorinated Biphenyls (PCB )
3 5 7 7 8 9 10 11 11 12 12 13
14 15 16 16 16 16 16 17 17 17 18 20 20 21
3
REQUIREMENTS OF OILS IN SERVICE
3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 3.12 3.13 3.14 3.15 3.16 3.17
General Viscosity Viscosity and flash point versus boiling range Low temperature properties Flash point Density Water content Particles Electrical breakdown (AC) Dielectric dissipation factor (tan delta/power factor) Interfacial tension Neutralization value Corrosion Oxidation stability Gassing tendency Impulse breakdown Influence of PAC on gassing properties and impulse breakdown 3.18 Streaming charging 3.19 Health and safety
Appendix 1 Appendix 2
Basic chemistry of transformer oils Refining techniques
23 25 25 26 28 28 29 29 30 31 31 32 32 32 38 38 39 40 42
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INTRODUCTION WHY MINERAL OIL Using mineral oil as a coolant and insulating medium in transformers is not new: indeed it has been in use for over a century. Today, mineral oil is still being used as an insulating medium because not only does it offer the best compromise between cost and performance, but compatibility with other transformer materials is also very good. Other far more expensive, fluids such as silicon oils, certain types of esters etc., are therefore reserved for applications where their specific characteristics can justify the higher price. They will not be further dealt with in this handbook.
THE IMPORTANCE OF QUALITY In their basic chemical structure, the types of mineral oils used today are not very different from the oils that were used 100 years ago. However, the quality of the oils has been greatly improved due to advances in refining techniques and because there is a better understanding of what is required in transformer applications. But why use better quality oils? To begin answering this question, compare the relative amount of oil used today with the amount used in the past for a certain installed power. The need for better quality becomes obvious.
Year
Litres of oil / kVA
1930 1960 1980
ca 3.5 1.0 0.25
Higher thermal load of the transformer oil requires better oxidation stability. The decision to use better quality transformer oils is also justified by the costs and reliability influence of a transformer failure regardless if it is caused by bad insulation from sludge formed or deteriorated paper insulation. The expected lifetime of a transformer today can be up to 40 years and the same expectation goes also for a high quality transormer oil.
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It is interesting to note that if low quality oil is chosen, the performance of the oil will not become apparent for some time – approximately 10 years – by which time the transformer’s warranty period will have expired (the majority of transformer failures in the early years are due to mistakes made in manufacturing, transportation and installation). It is easy to compare the costs incurred by shorter transformer lifetime and/or shutdown against the relatively low extra cost of high quality oil. Because the lifetime of the paper depends on the stability of the oil (when the oil deteriorates, degradation of the cellulose fibres accelerates) it is obvious that it is preferable to use a good quality oil from the beginning, rather than wait for deterioration of the paper, damage which is irreversible. A study by US inspection and insurance companies found that: * 10% of all power transformer failures were due to deterioration of insulating material. * Internal failure overloading in high voltage windings was promoted by deposits of material (sludge). For these and other reasons it is important to understand the influence of different oil parameters when selecting oils for electrical equipment, especially transformers. The main difference between transformer oil production, past and present, is that the industry has come to specialize in core competence areas: companies that produce transformer oils are specialists, unlike fuel producers. Today, by working with crude oil supplies of consistent quality and consistent production conditions it is possible to produce oils of very high quality.
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1. HANDLING AND STORAGE 1.1 GENERAL When a transformer oil has been properly produced to fulfil specified requirements, the next decisive step is to store and deliver the product, without affecting its properties. A number of properties crucial to the performance of the oil can be influenced during storage and handling. A high level of expertise is required to maintain the quality of transformer oils, because they are so easily contaminated. Below, the risks that are to be avoided and the precautions that are to be taken in connection with the handling process will be discussed. Some oils, especially used oils, may be harmful and therefore should be handled with care and necessary protection. For further information please see section 3.19 Health and Safety. The aspects of handling and storage of transformer oils are given to safeguard the properties of transformer oils. The requirements are explained in detail in chapter three.
Compatibility As a rule of thumb, new transformer oils conforming to one and the same specification are miscible with each other in all proportions. However, the characteristics of the blend should be tested if there are any doubts. The most important parameters to check are: • Interfacial tension • Dielectric dissipation factor, tan delta (power factor) • Oxidation stability The blend must of course meet the specification.
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There are materials which can influence the oil properties and/or cause problems in handling, and this should be considered in advance. Some oils might have higher solubility which can influence the rubber in gaskets, for example. This in turn may influence oil properties such as interfacial tension, dielectric dissipation factor, colour, and it may even lead to leakage. It is therefore important that the rubber is oil-resistant. Paints used in tanks, rubber bags and other liner materials should be tested for compatibility.
INSTRUCTIONS, ROUTINES AND QUALITY ASSURANCE All handling actions and routines for Nynas Naphthenics are documented in instructions for the guidance of our personnel and subcontractors at the depots, and, later on, with our customers. The instructions are part of our quality system, and their development, distribution, implementation and effectiveness meet the requirements of ISO 9001, to which Nynas has been officially certified since 1991. For the handling of our oils, including transformer oils, the main instructions for depots are very comprehensive and include all the steps necessary to deliver products to our customers. Independent inspectors, who have the knowledge and authority to supervise and safeguard the deliveries, are used for all shipments and many road/rail transport operations.
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1.2 STORAGE IN TANKS Tank requirements Storage tanks used for transformer oils are no different from tanks used for other oils or chemicals. The material is normally mild steel or stainless steel. The mild steel tanks can be coated with oil-resistant paints. Compatibility with the transformer oil has to be checked or recommended by transformer or oil producers. The water content of a transformer oil greatly affects its insulating properties. In storage tanks this means that contact with humid air must be avoided, especially in warm climates with relative high air humidity. The most common way of doing this is to equip the tank with a silica gel breather which extracts the humidity from air entering the tank. It can also be achieved by connecting a nitrogen or dry air source to the tank via a pressure valve. With such equipment, the water content in the transformer oil can also be lowered to approximately 10 ppm by bubbling the dry gas through the oil. This is the preferred technique. If the product has been contaminated with water, it is important that the tank has a sloped bottom with a low suction point, to drain off free water before final drying. It is also important to keep the oil dry in mild steel tanks, to prevent the tank from rusting. For this reason the tank must also have a discharge connection some distance above the tank bottom, to prevent particles from being sucked out together with the product. This will also influence the lifetime and efficiency of the particle filter. The filters in this case are either those located at the loading station or at the customers, in the degassing unit or in a factory system. In the storage tanks for delivery direct to customers, the transformer oils normally have a water content of 20 ppm or less. The loading line should be equipped with a particle filter that has a nominal pore size of not more than five micrometers.
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Dedicated handling It is vital to keep the tank(s) completely separate, dedicated for use with transformer oil. This applies of course to all piping and lines that are used to transport oil to loading stations and other shore tanks. If it is not possible to keep the tanks/lines separated from other products, cleaning must be carried out to a degree and with a technique dictated by the character of the previous product. There are a number of products which can be very harmful for a transformer oil, and where the risk of contamination is obvious, even after cleaning. They can be grouped as: • Engine oils • Heat transfer oils • Used oils • Other formulated lubricants • Halogenated hydrocarbons
Inspection routines and sampling The quality of the transformer oil has to be checked against the requirements according to established routines. The following general guidelines can be given, but the frequency and the extent will depend on local factors such as handling system design and type of quality system: • Shore-tanks and lines must be inspected for cleanliness before filling up with new product. If not, the quality of the old product must be known (analysed). • After filling the tank, the product should be sampled, analysed and approved against specification. • If turnover of the product is low, the product should be analysed regularly or before delivery to a customer. The analysis of these samples should only concern parameters influenced by storage, e.g. dielectric dissipation factor, water content, interfacial tension and appearance. The sampling should generally be done according to IEC 475. However an average sample from a tank could also be a running sample and supplemented with an absolute bottom sample. It is essential that the sampling equipment is dedicated for transformer oil, or is at least thoroughly cleaned before use. The sample bottles should be new, dark and with suitable seals and labels. If white bottles are used, they must be kept in a dark storage place.
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1.3 CHOICE OF VESSEL 1.3.1 Transport in ships Ships are normally used only for transportation from a refinery to a depot, for further storage, before distribution to end customers. The ships should be of the category “chemical tankers”, with stainless steel or coated tanks and line/pump systems which are easy to clean and drain. Ships dedicated to transporting base oils, where the previous cargo is known, can also be used, providing the cargo was of the same nature and refined to the same degree as the transformer oils. Note that even in the case of contamination by well-refined, paraffinic base oils might influence the low temperature properties of a transformer oil. No formulated oil products such as hydraulic oils can be tolerated as a previous cargo without thorough cleaning. Anything within the category of engine oils cannot be accepted at all as a previous cargo.
Cleanliness Keeping the product dry is the most common problem when transporting transformer oils in ships’ tanks. In some ships it is possible to pass a flow of nitrogen through the oil or put a nitrogen blanket on the top of the tank. Silica gel breathers are not suitable for ships’ tanks, due to water and high humidity. Tanks, lines and pumps are normally very easy to drain, clean and inspect for suitability. Information about the sensitivity of the product must be given to all people involved in loading, discharge and transportation. It is essential to inspect the ships’ equipment for product handling before use and to check the product very carefully after loading and discharge. Even with perfectly functioning quality systems, one would imagine that inspections are not needed, but there are still too many uncontrolled factors which can influence product quality. Although water is the most common problem, the most costly and time-consuming problems are caused by chemical contamination that is the result of poor cleanliness and/or an incompatible previous cargo. See also Section 1.4.3
Sampling Running samples, or an average of level samples should be taken from each loaded tank and supplemented with an absolute bottom sample. These samples should be kept for an appropriate time. For analysis and release of product, a composite sample per product is prepared. The requirements for sampling equipment are the same as those described on page six.
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1.3.2 Transport in road tankers, railcars and containers Deliveries by road are by far the most common means of transportation. Over the years, road tankers and containers have become safe methods of transportation. Special road tankers equipped with silica gel breathers are used when the requirements for dryness are extra high. When deliveries have to be made direct to a site where no degassing unit is available, this requirement is understandable, even if this procedure is not to be recommended, since all transformers should be filled via a degassing filter. For other deliveries where the oil is degassed at site, these tankers make for extra costs with minimal benefit. Rail tankcars are considered very safe in terms of contamination risks and can be equipped in the same way as road tankers.
Cleanliness Road tankers and rail tankcars are usually made of stainless steel, sometimes aluminium, and are easy to clean. The loading/discharge lines are short and easy to inspect, and there are no pumps involved if not specifically requested by the customer. Pumps, due to their design are difficult to clean and therefore involve a risk of contamination. They must be either dedicated for transformer oils, or very thoroughly cleaned, if possible by flushing with the product itself or a low viscosity naphthenic base oil. All hoses should be dedicated for use with transformer oils, since they are very difficult to inspect directly. An assessment of cleanliness must be based on a sample obtained by flushing the hose. Road tankers should be cleaned and inspected, unless the previous cargo was a transformer oil or base oil that can be identified and accepted. A visual inspection of tanks, lines and valves should always be performed to check for cleanliness.
Sampling Samples to verify the quality of a transformer oil load should be taken at the following points: – at the end of the loading line, to verify that the right product is loaded and is up to specification. – from the different compartments, as running samples, to yield a satisfactory average. After approved analysis the different compartment samples may be mixed into an average sample.
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– if the transport vessel is filled from the top, underline samples should be taken, and analysed, from each line, to verify that no contaminants are present in the discharge system. The samples must be taken with clean equipment or equipment that is dedicated for transformer oil use. The bottles/containers used for storage should be of glass or aluminium. Glass bottles for long-term storage have to be dark, or kept in the dark. If other materials are to be used, they should be tested for suitability.
1.3.3 Transport in “flexi-bags” (rubber bags) Together with euro-containers, “flexi-bags” (rubber bags) are sometimes used for transformer oils. The advantage is of course that the rubber bag can be returned as a small package after use while the container is used for other types of cargoes. There are, however, disadvantages and risks connected with these rubber bags. First of all, there is the difficulty of inspecting them before they are reused. Either they have to be dedicated or to have been cleaned thoroughly. The material in some of the bags is also questionable and must be checked for compatibility with the transformer oil, unless it has been approved by the oil supplier or user.
Cleanliness The requirement for cleanliness is the same as for other bulks. Complications arise because of the difficulty of inspecting, or of keeping track of the dedicated rubber bags. This adds to the importance of sampling and analysing the loaded product.
Sampling The same requirements for line samples should be applied as for other bulk deliveries. The rubber bag has to be equipped with some type of sampling device to make it possible to take samples of the insulating oil after loading without spillage of oil. The problem is that it is not possible to take an average sample (i.e. a running sample: a mix of the top, middle and bottom samples) from a rubber bag. This results in less certainty about product status after loading.
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1.3.4 Transport in drums Choice of drum Steel drums of approximately 210 litres are the second most common method for delivering transformer oils. The drums are made of mild steel and have two openings sealed with screw caps, of which tri-sure is the most common type. The thickness of the steel varies: for site deliveries of transformer oils, 1.0 mm steel is normally used. Due to the difficulties and costs of cleaning and inspecting used drums, new drums offer a high degree of security and are manageable at a reasonable price. However, the empty drums should be randomly checked by visual inspection for cleanliness, especially if they have been stored empty for some time. The drums should be kept with the caps on during storage before filling. The main thing to check for is rust formed by air humidity or free water. Some drum suppliers offer drums filled with nitrogen, which reduces the risk of formation of rust inside the drums before filling.
Cleanliness & storage of drums Due to the risk of contamination from foregoing products, a cleaning procedure for the drum filling system is very important. These systems are not easily inspected, and even if they are well drained, pumps and filters might still trap the previous product. The drums are filled through a pipe inserted down to the drum bottom, via one of the openings. The drum is normally placed on scales to obtain the correct weight. After filling, the drums are systematically sampled and sealed. It is important to keep a certain free volume in the drum to allow for volume expansion of the oil caused by changing temperature. It is most important to sample and test the oil from the first drums. This is where contamination is most likely to be identified. In some cases the drums are filled with nitrogen or dry air before filling with oil to avoid water pickup from humid air. This is relevant for weather conditions with high humidity and relatively high temperature (>60% relative humidity and >20°C). These precautions, however, do not replace the recommendation to fill oil into transformers via a degassing filter. It is also important to check the seals and to tighten the screw caps with the prescribed torque. Even if a sealed drum seems to be properly closed, leakage of water through the caps can occur, and therefore the drums should be transported and stored upside down or horizontal until use.
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At storage sites the drums should be stored on pallets and not placed directly on the ground (e.g. on planks or boards) and protected by suitable shelter from rain and sunlight. The drums should be placed upside down or on their side until used. Shelf life will be affected by temperature changes so the drums must be kept as cool as possible during storage. If there is some oil remaining in a partly used drum it should be stored on its side, protected as above, with the oil level above the bung. Special attention should be given to the rubber gasket around the bung when closing it, as tightening it too much will cause damage. It is not advisable to store half-emptied drums for long periods due to the risk of contamination.
Sampling The same requirements apply for line samples as for bulks. For the drums themselves, the number of samples and how to take them is defined in IEC 475. In brief, the procedure can be described in the following way: A bottom sample should be taken from drum numbers 1, 2, 5, 10, 100, 200, etc... until the last drum, and each sample should be visually examined for particles and haze. A composite sample from all drum samples should then be analysed against specification. If a contaminant is detected, the check must be extended until an approved drum in the series is found. The contaminated drums must be segregated and an oil expert should decide how the oil is to be used (disposed of). Drum number 1 should also be checked for contaminants, by analysing, for example, water content and dielectric dissipation factor.
1.4. CONTAMINANTS – AND POSSIBLE CORRECTIVE MEASURES 1.4.1 Water Water is the most common contaminant in transformer oils during handling and storage. This is of course due to the presence of water in almost any environment and the fact that water is also widely used for cleaning transport vehicles and handling equipment. There are three main ways of getting rid of the water. These do not include heating, because water solubility in oil increases with increasing temperature. (Please see page 29, figure 5). Large amounts of free water must be drained off when it has precipitated to the bottom of the tank/container.
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Dissolved water can be picked up by dry air or dry nitrogen bubbled through the oil. A slightly elevated temperature will speed up the drying process by increasing the water solubility of the air/nitrogen. The final method is degassing, which is a very common technique and which is also the only suitable one in some cases. The equipment can be either stationary or mobile. The technique is to heat, vacuum treat and filter the oil through a particle filter. The heated oil is exposed to a vacuum, which causes the water to evaporate to a high degree. There are numerous manufacturers of this kind of equipment. However, the equipment needs a lot of electricity to function and is quite expensive to buy. Relatively inexpensive equipment and low running costs make air drying the cheapest method .
1.4.2 Particles Particles will, together with water, lower the breakdown voltage. Particles are also present in the oil environment when it is stored, transported or filled into a transformer. Particles are removed by simple filtration through particle filters, which are also a part of degassing filters. When loading transformer oils for delivery to customers, a five micrometer filter, or smaller, should be used. The lifetime of these filters depends upon the amount of particles and fibres they have to remove from the oil. Due to collected particles, the pressure drop over the filter increases up to the maximal pre-given value, which indicates when it is time to change the filter cartridge.
1.4.3 Chemical contamination Small amounts of chemical contaminants can enter the oil during transport, handling or filling of the transformer. The contaminants come from other products that have been handled in the same equipment. Their nature varies, but they often share the common characteristics of being strongly polar and surface active. In these categories of products the most common types are engine oils, metal-cutting oils, rustprevention products, detergents, vegetable oils and their derivatives, etc. The list is long and knowledge about a specific contaminant has to be sought from a transformer oil supplier or a transformer producer. Chemical contaminants of these types will influence the values for dielectric dissipation factor and/or interfacial tension. The ageing properties might also be affected. These polar contaminants can be removed by treatment with activated clay.
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Even after clay treatment, however, there is no guarantee that the oil will be unaffected and restored to its original condition. Added or natural inhibitors in the oil might be removed by clay treatment and non-polar parts of the contamination will be left in the oil, possibly leading to shorter product lifetime. On the positive side, some lowrefined oils can gain in oxidation stability after clay treatment. See also page 56 in the refining section, where clay treatment is used as the last polishing step in refining. Please note that used clay has to be handled as environmentally hazardous waste. After clay treatment, the oil must always be tested for oxidation stability among other analyses.
1.4.4 Base oils/Solvents Base oils/solvents will influence the viscosity and flash point properties of an oil; by how much will depend on the amount introduced into the oil. Small amounts of base oils will normally not have an excessively negative effect on the transformer oils, as they are mostly clean and well-refined nowadays. Depending on the viscosity of the base oil, however, it will influence cooling properties of the transformer oil; in this case, the viscosity of the contaminated transformer oil should be analysed. Even in relatively small amounts, a low-refined base oil might decrease oxidation stability. If it is a paraffinic oil, the low temperature properties might be damaged. Solvent contamination will almost certainly have an adverse effect on the flash point. The problem with these types of contaminants is that little can be done to correct them. Apart from dilution, when small volumes are involved, re-refining or downgrading to fuel are the only possible measures.
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2. MAINTENANCE OF TRANSFORMER OILS IN SERVICE 2.1 GENERAL The cost of a transformer is high, but monitoring the performance of the transformer system via the oil is inexpensive compared to the costs of a failure in a transformer and the costs of an interruption in power supplies. This is absolutely true for power transformers, but with small distribution transformers, the cost has to be justified case by case, by for example a “What If” study. In combination with a computer-based expert system for interpretation of analysis results, and for storage of previous transformer operation data, the monitoring of transformers in service is even more to be recommended. For further guidelines and follow-up recommendations, it is advisable to contact the producer of the transformers and/or power distributors/independent laboratories.
Choice of oil To ensure the long service lifetime of a transformer oil (i.e. cost performance considerations), the most important step is to select an oil that has the properties required for the equipment in question: different equipment needs different oil grades. For example, a high-voltage, highloaded transformer demands a better oil than a low-voltage, lightloaded transformer. Normally, the producer of the equipment recommends the type of oil to be used, since the oil should be considered an essential part of the equipment and not just an undefined extra poured into the transformer. This is the modern approach to quality thinking. (Compare this with the automotive industry, which provide detailed specifications for the types of oil to be used in the different parts of a vehicle.)
Transformer diagnosis A transformer oil carries information about the condition of the transformer. Analysing the oil in service can therefore give early warnings about paper degradation, hot spots, electrical faults and problems with moving parts such as pumps. To avoid serious problems, these data can be used as a guideline for corrective measures in the transformer.
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2.2 SAMPLING To ensure that the sample is representative of the oil in the equipment that is to be tested, strict routines have to be followed when performing the sampling. If not, the analysis results might lead to false conclusions concerning the status and entail time wasting and expense in obtaining transport and testing the sample. Detailed sampling requirements are given in the IEC 475 standard. The following, in particular, should be noted: • Ensure that sampling is done by an experienced person, i.e. someone who is aware of the sensitivity of transformer oils and who will only use equipment that is clean, dry and in other respects suitable. There have been cases of samples being taken in engine oil bottles or alcohol bottles. Doing so will affect the electrical dissipation factor, flash point or water content. Just a few ppm of engine oil will destroy the dielectric dissipation factor. • Normally, oil samples should be taken from “living oil”, i.e. from oil in circulation. Only use the bottom valve of the tank, when a test for free water and sediment has to be performed. • Start the analysis by draining a sufficient volume of oil from the sampling line. • Cleaning of the sampling container is especially important, if the oil is to be tested for particle content (described in IEC 970). • Rinse the container with the liquid being sampled according to the following steps: – Let the oil flow down the side of the container. This is to prevent air from becoming mixed and trapped in the oil. This is extremely important when samples are taken under humid conditions where water saturation can be very rapid. Alternatively, fill the sampling container with a clean tube leading from the transformer to the bottom of the container, and let the oil fill the container from the bottom, until it overflows. – Because the container should be filled to 100% of its capacity, glass bottles are less suitable since a small air volume has to be left for expansion. – After sampling, ensure that the cap is clean, undamaged and correctly attached to the container. Some rubber seals might affect the oil. – Label the sample so that it can be easily identified. – Store in a dark place or in a suitable box if glass or light plastic bottles are used. Mineral oil is usually very sensitive to UV light and may deteriorate if exposed to light. This will first be seen in a reduction of the interfacial tension. – For gas-in oil-analyses, special sampling equipment has to be used; the procedure is detailed in IEC 567.
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2.3 WHAT TO ANALYSE AND WHY 2.3.1 Colour and appearance Colour and appearance give rapid and useful information that can be obtained on site. An experienced person observes immediately if something is abnormal. Combined with the smell, much information can be acquired. Dark colour may indicate that the oil has started to deteriorate, which is also the first step to free sludge. The appearance of an oil can indicate if free water is present and if the oil contains any impurities such as fibres or cellulose particles. A bad smell may indicate arcing, which causes cracking of the oil. However, systematic documentation of these observations is necessary to ensure continuity in the event of personnel changes.
2.3.2 AC-breakdown voltage The AC-breakdown voltage is of importance as a measure of the ability of an oil to withstand electrical stress. The breakdown voltage depends on the water and particle content of the oil. It is particularly important to check this before starting-up a new transformer and also when the transformer oil and paper insulation start to deteriorate, because the deterioration process generates water and particles.
2.3.3 Water content The water content in the transformer oil gives an indication of the water content in the paper material. Too high a level of water in the oil indicates that the paper also contains a lot of water, and this will affect the ageing of the paper, i.e. trigger decomposition of the fibres in the paper, which leads to irreversible damage that might cause an electrical breakdown in the transformer. Two more things are worth noting: old transformer oil that has started to oxidise has a higher saturation level for water than a new oil; water is also produced during oxidation both from oil and paper, which will further accelerate the breakdown of the paper.
2.3.4 Neutralization value The neutralization value indicates if the oil contains any acidic material. A high or increasing value indicates that the oil has started to oxidise. A high value might cause problems with corrosion and the acid can form soaps with metal ions in the oil and affect electrical properties. These acids will also increase the solubility of water in the paper because of their polar structure. These acids also promote the degradation of the paper (catalytic action).
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2.3.5 Dielectric dissipation factor and/or DC-resistivity These characteristics are both very sensitive to contaminants and ageing products. In some oxidation stability tests, the dissipation factor is measured in the oil after the ageing test to indicate the ability of the oil to withstand oxidation. These tests normally give similar indications of impurities, so it is not necessary to do both tests. However, DC-resistivity is more affected by the water content of the oil.
2.3.6 Interfacial tension This is a very sensitive analysis and can, in combination with dielectric dissipation factor, give an early warning signal when the deterioration of the oil starts (see section 3.14 Oxidation stability).
2.4 FILLING A TRANSFORMER WITH NEW OIL When a new oil is pumped into the transformer, it loses some of its properties, such as dielectric dissipation factor and interfacial tension. These parameters are very sensitive to contaminants from the transformer, and may be introduced during handling and filling. The recommended limits from IEC 422 of setting values for unused mineral transformer oils filled into new power transformers, are presented in the table on the facing page. The figures given are compared with the requirements in IEC 296 for the setting values of the same oils before they are filled into the transformers. The water content in the oil to be filled into 72.5 kV-type transformers should be agreed upon between supplier and user, depending on local circumstances. The table below comes from IEC 422, but different transformer producers might have stricter requirements on water content and electrical breakdown. For transformers larger than 170 kV, a maximum of only 5 ppm water is required by some producers/users, compared to the IEC 422 maximum recommendation of 10 ppm. It is very difficult for oils to pass the requirements in the table, if they have not been degassed, indicating that it is absolutely necessary to fill the transformer with a degassed and filtered oil. It is very important to check that the degassing unit is clean and is not contaminated with used oil. If the unit contains used oil, the dielectric dissipation factor and resistivity might be affected and fall outside the levels specified in the table, and this
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might also lead to a shorter lifetime for the oil in service. It is also necessary to ensure that the unit has not been used for PCB contaminated oils. We also know that silicon oils handled by the same system might contaminate mineral oils and cause excess foaming. Transformer range Properties
<72.5kV
72.5-170kV
>170kV
Colour
max 2.0
max 2.0
max 2.0
max 15
max 10
max 30 in bulk
Water content mg/kg
New oil requirement according to IEC 296
Interfacial tension (mN/m)
min 35
min 35
min 35
44 for new oil as typical value
Dielectric dissipation factor 90 °C
max 0.015
max 0.015
max 0.010
max 0.005
min 60
min 60
min 60
min 40
min 50
min 60
Resistivity 90 °C G ohm m (G=giga=109) Breakdown voltage (kV)
min 30 before/min 50 after treatment
A portion of the oil will evaporate together with the water. The filtering temperature should therefore not be too high and it should be related to the vacuum. For example, ASTM D 3487 recommends a maximum of 80 °C, if a pressure of 1mmHg in the vacuum equipment can be reached. This is especially important for inhibited oils where the phenolic types of inhibitor have a higher vapour pressure than the oil and the lifetime of the oil might be shortened. If intermediate storage is used, make sure that it is suitable for transformer oils. Please see under heading “Handling and Storage”, section 1.
2.5 FREQUENCY OF OIL TESTING It is very difficult to give a general recommendation about how often a transformer oil in service should be tested, and how far it can be permitted to deteriorate. This has to be done on a case-by-case basis, depending on the circumstances. For example, owners of large power transformers will probably check the transformer regularly, but for small distribution transformers, owners tend to accept a higher risk. The risk assessment, however, should be based not only on the size of the transformer, but more on the effect of a failure. A “What If” study could be carried out to evaluate costs and other consequences of a failure.
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In a risk failure analysis, the trend in the results must be considered: e.g. increase in tan delta versus the time, metal content versus time, neutralization value versus furfural content, etc. In IEC 422 electrical equipment is divided into eight different classes, with different recommendations for follow-up frequency. In the following table only two of them are included: one high-loaded category O power transformer with a voltage above 420 kV and one low-loaded of up to 72.5 kV, category C. In addition to these tests, flash point can be measured and the decrease from initial value should not be more than 15 °C. Flash point should be checked if an unusual smell is noted. This could indicate that the oil has been exposed to high arcing and has thus cracked into low boiling components. The inhibitor content can be measured to evaluate if the inhibitor content is drastically reduced. The metal content of the oil, as particles, can be measured to evaluate if any mechanical problem exists in the transformer, e.g. moving parts with wear problems. The frequency guidelines facing side are from IEC 422. In practice, the different power distributors have longer or shorter follow-up periods. For the more important equipment most power suppliers have a regular follow-up put into a computer system that decides when a sample shall be taken. Trend analysis can be carried out in these systems and experience from all types of equipment under different working conditions can be gathered.
19
Property acc to IEC methods
Frequency
Recommended action limits
Action
Appearance, sediment and sludge
Not a routine test. To be done in combination with other tests
Sediment or free sludge
Recondition the oil or change to new
Breakdown voltage
After filling, refilling or reconditioning prior to energizing. Then after 12 months, for Cat. O every two years and for Cat. C every six years.
Cat. O 50kV Cat. C 30kV
Recondition or, if more economical, replace the oil.
Water content
Cat O: After filling or refilling. Then after 3 and 12 months and after that in connection with dissolved gas analysis Cat. C not a routine analysis
Cat. O 20mg/kg
Check the reason and consider reconditioning. If free water, drain off before reconditioning starts.
Neutralization value
Every six years
max 0.5 mgKOH/g
Replace or recondition
Dissipation factor 90°C
Cat. O: After 12 months and then every six years Cat. C not a routine test
Cat. O max 0.2 Cat. C max 1.0
Check with manufacturer’s instruction.
Interfacial tension
Every six years
min 15mN/m
Investigate
Cat.C Free water at room temperature.
2.6 OTHER ANALYSES TO EVALUATE TRANSFORMER STATUS 2.6.1 Gas-in-oil analysis and furfuraldehyde content These tests are carried out in order to evaluate the physical condition of the transformer with regard to factors such as arcing, hot spots and paper deterioration. The importance of these tests is increasing, due to the development of sophisticated analysis equipment: High Performance Liquid Chromatography (HPLC), Gas Chromatography (GC), etc. Gas-in-oil analysis and interpretation thereof is specified in IEC 567 “Guide for sampling of gases...” and IEC 599 “Guide for the interpretation of the analysis of gases...”. Gases will form in oil-filled transformers due to normal ageing but also, to a much greater extent, as a result of failures. The reasons for the failures can be interpreted from the types of gases that are formed. The manufacturers and the power utilities have built up their own
20
knowledge concerning evaluation. The detection of the gases is performed by gas chromatographic methods using different ways of extracting the gases from the oil. IEC 567 has been revised (1992) and includes more effective methods. The following gases can be analysed: hydrogen, oxygen, nitrogen, methane, ethane, ethylene, acetylene, carbon monoxide and carbon dioxide. The amounts and ratios between the gases are used for the interpretation of probable failures. In the table below there are some examples of interpretations.
Nitrogen + 5% or less oxygen.
Normal operation of sealed transformer.
Nitrogen + more than 5% of oxygen.
Check for tightness of sealed transformers.
Nitrogen, carbon dioxide, carbon monoxide.
Transformer overloaded giving some cellulose breakdown. Check operating conditions.
Nitrogen and hydrogen.
Corona discharge causing electrolysis of water or corrosion.
Nitrogen, hydrogen, methane with small amount of ethane and ethylene.
Sparking or other minor faults causing some breakdown of the oil.
Nitrogen with high hydrogen contHigh energy arcing causing rapid ent and other hydrocarbons including deterioration of the oil. acetylene.
Carbon monoxide and carbon dioxide levels in the gas-in-oil analysis give an indication of the paper deterioration. But a more precise and earlier warning signal about the status of the paper is given by measuring furfuraldehyde content of the oil. This is done by an HPLC method, see IEC 1198 (1993), where the detection level for furfuraldehydes is deliberately low, in order to give an earlier warning than the gas-in-oil analysis. It is a relatively simple analysis, though somewhat expensive equipment is needed, but it gives very useful information as a routine test.
2.6.2 Polychlorinated Biphenyls (PCB) New mineral oils, produced from crude oil, do not contain any PCBs. PCBs originate from synthetic insulating liquids and they were originally used as insulating liquids because of their good electrical properties and low flammability. After their negative environmental impact was discovered, their use was banned in many countries. There is always a danger that PCBs may be introduced into new transformer
21
oils by mixing with re-refined oils, or as contamination from used oils. Therefore PCB content has to be measured in any mixture of old and new oils. It might also be necessary to measure the PCB content of oils that are sent for disposal. In many countries, PCB-containing oils are classified as hazardous waste and require special methods of disposal.
References: 1) IEC 296 Specification for unused mineral transformer oils for transformers and switch gears. 2) IEC 970. 3) IEC 1198. 4) IEC 422 Maintenance and supervision guide for transformer oils in service. 5) A guide to transformer maintenance. S.D. Myers, J.J. Kelly, and R.H. Parrish. TMI, 1981. 6) IEC 567 Guide for sampling of gases and of oil from oil-filled electrical equipment and for the analysis of free and dissolved gases. 7) IEC 599 Interpretation of the analysis of gases in transformers and other oil-filled electrical equipment in service.
22
3. REQUIREMENTS OF OILS IN SERVICE 3.1 GENERAL The oil in a transformer has several functions, the most important of which are of course insulation and cooling. Another function is to carry information about the condition of the active parts of the transformer.
Specifications The main requirements for a transformer oil are listed in various national and international specifications and standards. However, these standards only state the minimum requirement for transformer oils, and many transformer producers and electricity companies have their own, stricter requirements, based on their own particular needs. Basic standards are IEC 296, BS 148, VDE 0370 and ASTM D 3487. See explanation below. The physical requirements are fairly similar, but with regard to oxidation stability, there are big differences between the common methods – IEC 1125 A, B and C, DIN 51554 (Baader test), ASTM D 2440. All of them try to simulate long-term oxidation behaviour in a short time. See also table on page 35–36. It is also worth noting that no real chemical requirement is listed, such as the nitrogen, sulphur or PolyAromatic Compound (PAC) content of the oil. These chemical components cause differences between oils which are not specified by the given parameters and will influence impulse breakdown, gassing tendency, streaming charging and oxidation stability. As can be seen from the properties listed facing page, specifications can be divided into four types. In the table, facing page, you will find different specifications, international and national, listed hierarchically. Individual transformer manufacturers and different power distributors also have their different specifications and requirements. We will now turn to consider some of the physical and chemical parameters listed in the specifications, as well as some unspecified parameters.
23
IEC 296
International standard
BS 148, ASTM 03487, VDE 0370 , etc
National specifications
ABB, GEC-Alsthom, etc
Transformer producer specifications
RWE, EDF, etc
Power distributor specifications
Summary of property requirements Chemical Oxidation stability Oxidation inhibitor content Corrosive sulphur Water content Neutralization number
Electrical properties Breakdown voltage Dissipation factor
Physical Viscosity Appearance Density Pour Point Interfacial tension Flash point
Additional requirements Impulse breakdown Streaming charging Gassing properties Aromatic structure Polyaromatic structure Solubility properties
Please also see table on page 45.
Compatibility The compatibility of different oils has always been a matter of discussion. It is however safe to assume that oils which meet the same IEC 296 class can be mixed together. In the following, we take a closer look at these requirements and what influence they have on transformer oils in service.
24
3.2 VISCOSITY The viscosity of an oil is important for the cooling of the transformer: the lower the viscosity, the better the cooling. Increasing temperature reduces viscosity, and a small change in viscosity with temperature means a high viscosity index (VI), while a big change indicates a low index. In lubrication applications, oils with high VI give better performance. In cooling applications a low VI is preferred, because lower viscosity at operating temperature means better cooling. Below we have compared two oils, one naphthenic and one paraffinic. Both have the same viscosity at 40 °C, but as can be seen there is a relatively big difference between the two oils at a normal transformer working temperature. IEC 296 Class II oil
High VI Paraffinic 4.2
Viscosity at 70 °C mm 2/s
Low VI Naphthenic 3.4
It is never an advantage to use high viscosity oils, because the higher the viscosity the worse the cooling properties. This gives higher working temperatures, higher losses, resulting in faster deterioration of the oil and the paper. A naphthenic oil is therefore preferable. IEC 296 is currently divided into three viscosity classes, I, II and III. Oils with viscosities of around 9-10 mm2/s are those which are mainly used today. Maximum viscosity values for the different classes are given below and, as will be seen, an oil satisfying Class II also meets the requirements for Class I. The difference between them is the flash point requirement
Viscosity at 40 °C (mm2/s)
I
II
III
<16.5
<11
<3.5
3.3 VISCOSITY AND FLASH POINT VERSUS BOILING RANGE An oil is a mixture of hundreds of different molecules and is therefore said to have a boiling range, rather than a boiling point. When the boiling range is higher, the viscosity of the oils increase. The inherent difference between naphthenic and paraffinic molecules gives a paraffinic molecule a higher boiling range for a given viscosity. See figure below.
25
°C 500
Figure 1 Viscosity Flashpoint Naphthenic oil 7.7 Paraffinic oil 7.5 Switch gear oil 3.5
450 400
144 136 100
Viscosity and flash point vs boiling range
Paraffinic
350 Naphthenic
300
Switch gear 250 200
% 0
20
40
60
80
100
Figure 1 shows two boiling point curves, one for a naphthenic oil and one for a paraffinic. Both oils have a viscosity of approximately 8 mm2/s at 40 °C. The third curve is for a typical switch gear type of oil with a viscosity of about 4 mm2/s at 40°C and a flash point of 100 °C. Transformer oils have roughly the same flash point, 140 °C, which means that the boiling curves start at the same temperature. The paraffinic oil will have a much higher boiling temperature at the 50 % point and at the end as well. This higher boiling point means that an oil refined to the same degree contains more PACs of three rings or more. This higher PAC content will affect properties like impulse breakdown and streaming charging. The three-ring molecule anthracene, for example, has a boiling point of 350 °C. This temperature corresponds to what is nearly the end point for the naphthenic oil, whereas more than 25 % of the paraffinic oil has a boiling point above 350 °C. More information on this subject will be found in the part covering extraction on page 55. The curves in figure 1 were produced with ASTM D 2887, a GC method used in refineries for optimizing and checking production. The column used for the method is of a non-polar type, calibrated with Nalkane. If a capillary column is used, more individual peaks can be identified, and so this latter method can be used as a tool for fingerprinting different oils for traceability.
3.4 LOW TEMPERATURE PROPERTIES Low temperature properties are important in a cold climate, and the major specifications include both pour point and viscosity at low temperatures. In some countries, Sweden and Canada among them, it is being discussed whether to increase the requirement, e.g. to specify that the cloud point should be the same as, or lower than, the pour point and to measure viscosity at a low shear rate, or at -40 °C. All these measurements are made to simulate the flow in a transformer during cold conditions.
26
Paraffinic oils contain N-alkanes which, when they are cooled down, can crystallise and impede the free flow of the oil; the actual amount of N-alkanes can be measured with a Differential Scanning Calorimeter, DSC. When a cloud point occurs in the oil, it is no longer a Newtonian fluid (i.e. a fluid that does not change viscosity at different shear rates) and is in fact a two-phase system. When an oil is cooled, the N-alkanes start to crystallise, release heat and show up in the curve as a difference between the sample and a reference. The area between the curve and a straight line then corresponds to the amount of N-alkanes. The crystallisation point correlates with the cloud point of the oil. In the upper curve, no crystallisation is visible for the naphthenic oil. Figure 2 ∆T
Cooling
Heating
The two DSC curves in Figure 2, one for a paraffinic and the other for a naphthenic oil, illustrate the formation of wax crystals.
N-base
P-Base
Temperature
±0
-100
Temp
Naphthenic oils contain few, if any N-alkanes. This means that no shear stress is needed to get the oil moving at low temperature. For a paraffinic oil, if used in a self-circulating transformer, the oil might be solid, even though it is possible to measure a viscosity with high shear rate methods, such as a standard viscosity test. The two curves in Figures 3 and 4 were plotted at -30 °C and -40 °C respectively. The values are taken from the IEC WG5 (Working Group 5) and are measured as dynamic viscosity at different shear rates. It is clear that the paraffinic oil at -30 °C has a higher viscosity at a low shear rate, compared to the naphthenic oil that does not change viscosity at different shear rates. The paraffinic oils fulfilled the viscosity at -30 °C with the normal kinematic viscosity measurements. Figure 3
3000
Brookfield viscosity at -30 °C
Paraffinic oil 2000
Paraffinic oil Naphthenic oil
1300
Spindel rpm 1
3
5
7
9
27
11
Viscosity Cp
Figure 4
8000
Brookfield viscosity at -40 °C
Paraffinic oil
6000
Paraffinic oil
4000
2000
Naphthenic oil Spindel rpm 6
10
14
18
22
26
30
3.5 FLASH POINT The flash point of an oil is specified for safety reasons. In the three IEC 296 grades, the following flash points are stipulated.
Flash point PM° C
I II ≥140 ° C ≥130 ° C
III ≥95 ° C
IEC specifies the PM (Pensky Marten) closed cup method. In USA the COC (Cleveland Open Cup) is used, which gives a 5-10 ˚C higher flash point value. The flash point depends on the light part of the oil and is extremely sensitive to contaminants from lighter oils such as gas oil or gasoline. Even though both methods yield relatively poor reproducibility, the closed cup method is preferred because it provides better repeatability.
3.6 DENSITY In cold climates it is important to specify oil density to avoid the occurrence of ice floating in the oil at low temperatures. This can occur when there is free water present in not energized transformers and which can cause failure during start up. Oils with high aromatic content have higher density than oils with more naphthenic and paraffinic molecules. The density decreases with increasing temperature and the standard coefficient 0.00065/°C is used for calculating the density at other temperatures than those measured. This coefficient will vary somewhat with the different oils, depending on the structure and degree of refining.
Nynas Naphthenics Nytro 10BN, Nytro 10X and Nytro 10GBN all have a flash point exceeding 140 ˚C and a viscosity less than 11 mm2/s at 40 ˚C, thus meeting the requirements of both IEC Class I and II.
28
Water content ppm 200
Figure 5
X Xylene
175
Depends on: • Polarity of the oil • Temperature
150
Solubility of water in oil
Transformer oil
125 100
Liquid paraffin
75 50 25 0
Temperature °C 0
10
20
30
40
50
3.7 WATER CONTENT The water absorption of the oil depends on the temperature and the amount of polar molecules. In figure 5 we can see that it is difficult to maintain a low water content in oil that is stored in areas where humidity and temperature are high. It is also obvious that just heating the oil will not reduce the total water content if there is free water in the system, the reason being that water solubility increases with temperature. If free water is present, however, the lower viscosity obtained when heating the oil gives faster separation but will increase the amount of water dissolved. From the same diagram we can also see that higher aromatic content (polarity) gives a higher saturation level for the water. During oxidation of the oil, water is formed as an oxidation product, in which case it is an advantage for the oil to have high solubility, so that there will be no free water. Oils with a high water content may foam when they are degassed. This is not real foam. Real, stable foam can be found in contaminated systems – for example oils contaminated with particles or other liquids incompatible with the oil, e. g. silicon oils. As a general rule, clean liquids do not foam.
3.8 PARTICLES Oil treated with modern refining techniques has a low particle content, but as soon as it is transported and stored this content increases. By passing the oil through a degassing unit, which contains a particle filter, the particle content will be reduced to an acceptable level. If the oil is circulated through the transformer and a degassing unit, it cleans the transformer from dust and loose cellulose particles. Figure 6 shows the results of a study on particle content in oil handled from the process plant down to storage and degassing. The upper curve is an oil taken after transportation and storage, the lower one after degassing and filtering.
29
Number of particles/100 ml Greater than indicated 100000
Figure 6 Particulate contamination after transport and storage and after filter
10000 After transport+storage 1000
After filter 100
10 Particle size, micrometers 0
20
40
3.9 ELECTRICAL BREAKDOWN (AC) This property is very complex and the measured value depends on particle content, type of particles, water content and the test method used. The normal method for specifying AC breakdown is IEC 156. In this method the electrodes are spherical or hemispherical at a distance of 2.5 mm and the voltage is increased by 2 kV/s until breakdown occurs. The result is stated as an average of six tests, due to the low repeatability of each test. Even a low-refined oil may have a high breakdown voltage, so this method tells us nothing about the refining of the oil. The removal of water and particles can give a breakdown voltage of more than 70 kV to any oil. The IEC specification has over 30 kV as a minimum level, and if the result is lower than this, all it requires is a simple degassing treatment to raise breakdown to more than 50 kV (normal value > 70 kV). Breakdown kV 90
Figure 7
80
Depends on: . Water content . Particle content . Temperature
70 60
Electrical breakdown AC
50 Clean oil
40 30 20 10
Contaminated oil
Water content, ppm
0 0
20
40
60
80
100
Methods other than the IEC 156 can be used for electrical breakdown, e.g. ASTM D 1816 and D 877 which are included in the ASTM D 3487 specification. ASTM D 1816 uses the same type of electrodes as IEC 156 and the results can therefore be compared if the electrode distance is the same or the result is calculated to the same distance. The other method, ASTM D 877, does not give comparable results due to different types of electrodes.
30
It is also interesting to note that high solubility in an oil keeps some of the sludge in solution that is produced when the oil starts to oxidise, thereby reducing the amount of free particles that can lower electrical breakdown. The amount of particles might also be influenced by the carbonisation of oil molecules that occurs in partial electric discharges. The amount of particles formed is related to the result of the carbon residue analysis of the base oil, and here the naphthenic oils have an advantage over the paraffinic oils.
3.10 DIELECTRIC DISSIPATION FACTOR (tan delta/power factor) This is a parameter that will always be found in a transformer oil specification. The loss angle depends on the amount of ions in the oil. A normal degree of refining always gives a low value for this parameter, but it is very sensitive to contaminants, e. g. engine oils. So big is the effect of molecules of this type, that just a few ppm will destroy the tan delta. Water itself does not affect this property, but can participate in forming stable complexes with oxidation products, or with other impurities to give high tan delta values. When an oil starts to deteriorate, an increase in tan delta can be found at the beginning of the oxidation process, followed, after a time by a decrease. What probably happens is that peroxides form together with metal complexes, as the first step of oxidation. These complexes produced have a strong polarity and a high content of ions, and so this causes an increase in dielectric loss. This peroxide will be decomposed into new radicals, forming oxidation products with a lower tan delta. After the initial decomposition stage, oxidation products, such as acids and esters form, causing the tan delta to increase again. Normal value for an oil as manufactured is < 0.001 at 90 °C and 50 to 60 Hz. In some specifications power factor is used instead of tan delta. The difference is little at low measured values.
3.11 INTERFACIAL TENSION The interfacial tension test measures the strength of the interface between oil and water. The interfacial tension depends on the polar groups in the oils, whilst tan delta (90 °C, 50 Hz) tells something about the content of ionizable contaminants.
31
Here are some examples of our analysis results for different oils. Tan delta
Interfacial tension mN/m
Water content ppm
Oil exposed to daylight stored in clear glass bottles
0.0031
36
50
Before test and reference stored in aluminium bottles
0.0010
44
18
This test tells us three things: oils are sensitive to light exposure, interfacial tension is more sensitive for detecting oxidation products, and tan delta and water content are higher in oils at the beginning of the oxidation process. (Heavily deteriorated oil in service may have interfacial tension values less then 18 mN/m).
3.12 NEUTRALIZATION VALUE In a well-refined oil the neutralization value must be less than 0.01 mg KOH/g oil, but because this method has a repeatability of 0.03, the minimum requirement is less than 0.03. This level, however, is too high to give any guidance on the quality of the oil. Well-refined, non-contaminated oils must have a target value below 0.01.
3.13 CORROSION In IEC 296, this requirement is based on a method where a copper strip is immersed in the oil at 140 °C. Its sensitivity is low, and many companies use alternative methods such as the silver strip test or potentiometric titration of mercapto sulphur in the oil. Corrosion is of course an important parameter of the oil, and for switchgears silver corrosion is one of the most important things to consider.
3.14 OXIDATION STABILITY There are two types of oil on the market, inhibited and non-inhibited. In fact all oils are inhibited – the inhibited ones with hindered phenol added (radical destroying) and the non-inhibited with natural inhibitors (peroxide destroying). The majority of all oils used in the world today are inhibited with phenolic inhibitors at different levels. Oxidation is influenced by the two main parameters oxygen and temperature. Without oxygen, the oil will not oxidise; however all oils contain a small amount of air even after degassing (in a sealed dried unit 0.05 to 0.25% oxygen by volume will still remain) which will participate in the oxidation. Heat accelerates this deterioration, for example: a
32
temperature that is 10 °C higher, reduces lifetime by half. This is a rule of thumb, but it is not true for all oils, because other reactions may start at high temperatures (compare with an egg stored at 40 °C and 100 °C respectively). What happens when an oil starts to oxidise? The first reaction is the creation of a free radical (1). This reaction is triggered by heat, UV light, mechanical shear and - also important in a transformer – high electrical fields. This step is important, and it happens in all oils. If nothing stops the reaction, the next step is the creation of peroxide through oxygen radicals (2) (3). This peroxide is not stable (4), and the next reaction may be for the peroxide to give two new radicals which can continue the oxidation(5). There are two basic types of anti-oxidants, radical- and peroxidedestroying. Radical-destroying stabilises free radicals by donating a hydrogen atom in reaction (1). Phenols and amines are well-known types. Peroxide-stopping prevents the formation of additional free radicals by decomposing the peroxide to a more stable compounds. The formation of radicals is important for stability. It is not fully understood, but the metal complexes we have already discussed (see page 31) are important. These metal complexes act as a catalyst for oxidation. Some complexes, though, are also known to be inhibitors.
RH ➝ R˚
(1)
R˚ + O2 ➝ RO2˚
(2)
RO2 + RH ➝ RO2H+R˚
(3)
RO2H ➝ RO˚ + OH˚
(4)
RO˚ + RH ➝ ROH + R˚
(5)
This is comparable to the vitamins our bodies need. We need a complex mix of different kinds, where C vitamins act as a water soluble and vitamin E as an oil soluble inhibitor radical destroyer. We also need some traces of peroxide inhibitors. It is well known that smokers need extra vitamins to protect themselves from radicals created in their bodies.
33
The oxidation process of different oils Figure 8, below, illustrates four types of oxidation behaviour, describing what happened to different oils during oxidation. Curve A is a white oil or some other absolutely clean oil. In this oil there is nothing to stop the oxidation, and you will find a high content of acid and yellow sludge as oxidation products, and also an increase in viscosity (ageing without vitamins). Curve B is an oil that contains natural inhibitors, and at the beginning of oxidation, peroxide-stopping additives (natural) stop the creation of radicals from peroxides. After some time, various radical-stopping molecules have been produced, e.g. polyaromatics, whose oxidation products are highly reactive phenols. The sludge produced is black. (The oil contains trace elements of peroxide destroying inhibitors from the start and produce radical stopping inhibitors during the ageing process). Curve C contains only phenol in a white oil. After some time the inhibitors have been consumed and oxidation accelerates as in a clean white oil. (Only vitamins without trace elements). Figure 8 Top
A
Oxidation behaviour
C
D
B
E Time
Curve D contains both natural and synthetic inhibitors. The type and amount of the natural inhibitors are less than in a fully optimized oil. Normally an oil produced to give a good response to inhibitors does not have the high PAC content necessary in an oil optimized to be noninhibited. As oxidation products, these PAC-based molecules can act as radical-destroying inhibitors and prevent further oxidation. Curve E shows the peroxides (see reaction (3), facing side) produced for the uninhibited oil in curve B. These peroxides also form a complex with metal ions.
34
Oxidation tests There are several methods for testing the oxidation stability of an oil. Remember, though, that oxidation is not the same as thermal stability. Thermal stability is the temperature when an oil starts to decompose without oxygen. The cracking temperature can be as high as 350 °C. The oxidation tests most commonly used in Europe are the IEC methods IEC 74, IEC 474 and the new IEC 813, methods which are today compiled in IEC 1125 as A, B and C respectively. In Germany, DIN 51 554 is used for testing oils. IEC 74 or IEC 1125 A has long been in use for testing uninhibited oil. It employs copper as a catalyst and with oxygen bubbling through the oil at 100 °C. Sludge and acid number are measured after the test. IEC 474 or IEC 1125 B mainly measures the volatile acids occurring as oxidation products. The test temperature is 120 °C. The catalyst is copper and oxygen is bubbled through the oil. A high induction time does not necessarily mean that the oil is better suited for use in a transformer than another oil with a lower induction time. The oil can be black and contain a large amount of non-soluble sludge, but only produce a small quantity of volatile acids. IEC 813 or IEC 1125 C measure both volatile and oil-soluble acids. The sludge is determined in the same way as in IEC 74 and 474. The temperature is 120 ˚C and a low flow of air is bubbled through the oil with copper as a catalyst. ASTM D 2112 is intended for transformer oils inhibited with phenolic type of inhibitors. The test is made at 140 °C in the presence of copper, water and with an over pressure of oxygen (90 psi). The time for the oil to react with a certain amount of oxygen is reported as the result. ASTM D 2440 is similar to IEC 74/IEC 1125 A, apart from the temperature which is slightly higher, 110 °C, and the test duration which is 72 and 164 hours. DIN 51 554 or the Baader test in which there is no air flow through the oil and it is only air over the oil which takes part in the oxidation process. The temperature is 110 °C and the catalyst is copper. Saponification number, sludge and dissipation factor are measured after the test. The measurement of saponification number instead of acid number is a little doubtful, because oxidation products not harmful to the cellulose or the copper will contribute to the result. The main question when discussing the above methods is which method gives the best correlation with an oil in service. The only way to establish this is to correlate results from transformers that have the same load and construction and that are filled with different oils that have different levels of oxidation stability.
35
Comparison of oxidation results Let us now compare three different oils. The first oil, Nytro 10GBN, is an uninhibited oil. The second Nytro 10BN is an uninhibited oil, which has been optimised for high performance in the Baader test and also given high performance in IEC 813. The third is Nytro 10X, an oil developed for high response to a synthetic inhibitor DiButyl ParaCresol (DBPC). But the base oil for Nytro 10X also meets the IEC 74 limit before the inhibitor is added.
Nytro 10GBN
Nytro 10BN
Nytro 10X
IEC 296 Specification
0.11 0.02
0.08 0.02
<0.01 <0.01
<0.4 <0.10
<50
>80
>236
≥120
0.27 0.06
0.17 0.06
<0.01 <0.01
IEC 1125 A NV mg KOH/g Sludge wt% IEC 1125 B Induction period h IEC 1125 C, 164 h NV total mg KOH/g Sludge wt% IEC1125 C, 500 h NV mg KOH/g Sludge wt%
0.04 <0.01
ASTM D 2440 72 h Total acid no, mg KOH/g Sludge wt%
0.14 0.03
0.09 0.02
<0.01 <0.01
0.18 0.05
0.10 0.04
<0.01 <0.01
0.03 0.02 0.20 0.04
<0.02 <0.01 <0.05 <0.005
0.08 0.06 0.30 0.10
0.02 <0.01 0.11 0.005
ASTM D 2440 164 h Total acid no, mg KOH/g Sludge wt% DIN 51554 Baader test, 140 h NV mg KOH/g Sludge wt% Saponification no, mg KOH/g Tan Delta
>0.6
DIN 51554 Baader test, 28 days NV total mg KOH/g Sludge wt% Saponification no, mg KOH/g Tan Delta
In the table we can see that the inhibitor in the inhibited oil Nytro 10X reacts and forms a stable ester which gives a high saponification value. This is a very stable molecule and, therefore, will not present any problems in the transformer. Note that the acid number of Nytro 10X after 28 days of Baader test is still very low – the same as for new oil – and that the same is almost true of the tan delta.
36
Interfacial tension
Acid value mg KOH/g and tan delta 0.05
Figure 9
0.045
Interfacial tension
0.04
40
0.035
Nytro 10 x 30
0.03 0.025
Open beaker test at 100 °C, Nytro 10X
20
0.02 0.015 Acid value
0.01
10
tan delta 90°C
0.005
Days at 100°C
0 0
2
4
6
8
10
12
Acid value mg KOH/g and tan delta
Interfacial tension
0.05 0.045
Figure 10
Acid value
0.04
40 Nytro 10 BN
0.035 0.03
30
0.025 0.02
Interfacial tension
20
Open breaker test at 100 °C, Nytro 10BN
0.015 0.01
10 tan delta 90°C
0.005 Days at 100°C
0 0
2
4
6
8
10
12
The test was performed in an open glass beaker at 100 °C with air above the oil. A copper strip is used as a catalyst. The method is used by Nynas Naphthenics AB for screening.
We may also note, in IEC 813 164 h and 500 h, that the Nytro 10BN oil has flattened out. The radical-destroying inhibitors, formed as oxidation products, are still working. Other studies show the behaviour to be a step-by-step increase in oxidation. Nynas has also tested other methods. In Figures 9 and 10 you will find some graphs illustrating what happens when oxidation starts in an inhibited oil and in an uninhibited one (Nytro 10X and Nytro 10BN respectively). An interesting point is that interfacial tension is one of the first parameters to change during oxidation.
Conclusion Different methods produce different results, and so in optimising the product we have to consider several methods and not just one. The inhibited oil Nytro 10X shows perfect response to the inhibitor and scores better than the uninhibited in all the tests we have performed. The long Baader test period shows the same. However, in general the addition of an inhibitor to an oil is no guarantee for superior
37
performance. The oil has to be refined in advance to a high level to be sensitive to the inhibitor intended. A traced content of PAC molecules together with the phenols, may produce antagonistic effects. Nytro 10BN meets all the requirements for an uninhibited oil, including the Baader test. Nytro 10GBN meets the normal standard requirements and generates less gas than the other two oils.
3.15 GASSING TENDENCY Some gassing will always occur in a transformer oil when it is exposed to partial discharges. This is because some molecules will reach a higher energy level and fragments will be detached from these molecules. The fragments found in oils are H2, CH4. If gas is produced in large quantities which are trapped because of the construction of the transformer, the bubbles formed are dangerous to the transformer. The reason is that they can cause an electrical breakdown due to the bad insulating properties of the gas compared to the oil. This is a known fact in the cable industry, where gas-absorbing oils have been used for many years. In modern transformers these problems should have been solved in the design with a low amount of partial discharges and good oil circulation. However some designs might have to be compensated with gasabsorbing oils. To find out to what degree an oil will absorb gas, the old Pirelli method that was developed for cable oils is still used, though it has been somewhat altered as specified in IEC 628 A and ASTM D 3484. Today there is an alternative method available, that developed in Germany, is now used across Europe. Known as the Soldner-Muller method, it is included in IEC 628 as method B. The gas used in the Pirelli method is hydrogen, and in the Soldner-Muller method nitrogen. Hydrogen absorption is quite clearly understood, but the nitrogen reaction is unclear.
3.16 IMPULSE BREAKDOWN Impulse breakdown is a property which is not usually described in the majority of specifications. Breakdown behaviour with DC impulse and a heterogeneous gap is very different from the AC strength. It is designed to simulate lightning striking a transformer during a thunderstorm. The result is independent of the contaminants influencing the normal test, IEC 156.
38
A needle and steel ball are used, as electrodes, at a distance of 2.5 cm. With a negative impulse to the needle, the breakdown has been found to depend on the degree of refining of the oil, with lower aromatic content giving a better/higher value. Some manufacturers of heavily loaded power transformers are interested in having a high impulse breakdown. The methods used, IEC 897 and ASTM D 3300, are quite similar, and the ASTM specification requires a minimum value of 145 kV negative. This value is obtainable with most oils on the market.
3.17 INFLUENCE OF PAC ON GASSING PROPERTIES AND IMPULSE BREAKDOWN It is well known, and it has been demonstrated in a number of articles, that aromatic molecules affect gassing properties and impulse breakdown. For gas absorption, high aromatic content is desirable. The aromatics react in a transformer in the same way as in the hydrogenation process in essence, absorbing hydrogen by saturating aromatic structures. In impulse breakdown, oils with high aromatic content, particularly with high PAC content, show low breakdown values. We also know that monoaromatics give a relatively high value. To test this, we constructed a test programme based on naphthenic oils with different degrees of refining to examine impulse breakdown and gassing properties. These measurements were carried out in the USA by Doble Engineering Company, please see table below. We correlated these results with our own HPLC method for determination of PAC-content. This method works on the principle that the polyaromatics are more polar than mono- and di-aromatics. We developed the method as a quicker and less solvent-consuming alternative to the IP 346 method. In this method a nitrile-type liquid chromatography Oils tested: Polyaromatics wt%
Aromatic content %
HPLC method
IEC 590
0.01 0.02 0.07 0.30 0.75
Impulse breakdown kV ASTM D3300
5 7 10 10 10
> 300 282 220 196 148
39
Gassing tendency µl/min ASTM D230 B +32.9 +26.2 +16.3 +11.3 +4.5
Polyaromatics HPLC % b.w. 1
Figure 11 Polyaromatics Aromatic content HPLC 5 7 10 10 10
0.01 0.02 0.07 0.30 0.75
0.1
Impulse breakdown >300 282 220 196 148
Gassing tendency
Impulse break down
+32.9 +26.2 +16.3 +11.3 +4.5
Impulse breakdown,kV
0.01 120
140
160
180
200
220
240
260
280
300
Polyaromatics HPLC % b.w. 1
Figure 12 Polyaromatics Aromatic content HPLC 5 7 10 10 10
0.01 0.02 0.07 0.30 0.75
0.1
Impulse breakdown >300 282 220 196 148
Gassing tendency
Gassing tendency
+32.9 +26.2 +16.3 +11.3 +4.5
Gassing tendency, µl/min ASTM
0.01 0
4
8
12
16
20
24
28
32
column (Alltech 600 CN) is used and the different aromatics are separated by polarity differences. By reversing the flow when monoand di-aromatics have passed, the remainder comes out as one peak. We use naphthalene as a marker and hexane as a solvent. This method measures not only polyaromatics but also other polar compounds, such as nitrogen and sulphur-containing molecules. The properties measured can be considerably influenced by nitrogen, especially basic nitrogen. Note that the last three oils have the same aromatic content by IR measurement, but differ a great deal in PAC content. The difference in aromaticity also depends on the distillation range, as we saw earlier. These oils, however, have the same boiling range. Nynas has analysed different oils on the market, and it is clear that uninhibited oils giving high oxidation stability also have a high PAC, in some oils it is possible to find 6, 7 and 8-ring PACs. As described earlier, these polyaromatics act as natural inhibitors that are added to the oil in order to protect the oil from oxidation.
3.18 STREAMING CHARGING When an oil is pumped through a duct, as in a transformer, negatively charged species from it can be adsorbed by the material on the duct walls. This means that the oil will be positively charged when leaving
40
PAC, % b.w. 2.4
Figure 13
2.2 2
Streaming charging
1.8 1.6
Oil type
1.4
High refined oil Inhib Medium refined Uninh Low refined Medium refined paraffinic
1.2 1 0.8 0.6
Streaming PAC HPLC charging 0.02 2 0.5 9 2.0 24 2.4 34
0.4 0.2
Streaming charging, µl/m3
0 2
6
10
14
18
22
26
30
34
the duct. Some authors claim that this is a serious problem in transformers, and a lot of research is in progress to explain the phenomenon. Because different transformers have different cooling systems, the occurrence may be more serious in some types of transformers than in others. Our oils were tested in this respect in the USA at the Doble Engineering Company. The method used was presented in IEEE Trans. PAS-103 No. 7 1984. The graph makes it clear that streaming charging is low in a clean oil with a low content of polar molecules. Once again, the aromatics in themselves are not so very important in this respect, but the basic nitrogen existing in oils at ppm or even ppb levels are more influential. It is extremely difficult, however, to measure such small amounts in a transformer oil that contains several thousand molecules. It may be concluded, though, that highly-refined oils are better than low-refined ones. It is shown that well-refined oils give a low value, but what happens when an oil starts to deteriorate? A very mild open-beaker oxidation test was performed at a temperature of just 100 °C. The results clearly show that an inhibited oil gives a low result compared with a non-inhibited oil. From this we conclude that if a low value of streaming charging is wanted, the oil must be well-refined and inhibited. Streaming Charging uC/m3 250
Figure 14
Streaming Charging lower for clean oil compared to oils that are refined to be not inhibited (Hetero and PAC molecules)
200
Streaming charging after oxidation 48h and 72h
150
Uninhibited
100
50 Inhibited oil 0 1
48
72
41
Time h
3.19 HEALTH AND SAFETY Low refined oils have shown evidence of being carcinogenic by the International Agency for Research of Cancer (IARC), a body within the World Health Organization (WHO). The finding is based on epidemiological studies made in the past, in for example the textile industry, where low refined oils were used. Although the correlation exists, it is important to relate the risk to other substances such as Benz alpha Pyrene (B(a)P) which is much more dangerous. Given good personal hygiene when handling transformer oils, the risk can be negligible. Low refined oils have to be labelled in accordance with laws in different countries. For highly refined oils, no epidemiological studies show any risk of cancer. The main question is how to specify a low refined carcinogenic oil and a high refined oil that is not carcinogenic. The following points will go some way in answering these questions. In Vivo test. The only test accepted is skin painting of experimental animals. The literature contains much data to show that low refined oils are carcinogenic while highly refined oils are not. In Vitro test. The Ames test, in which micro-organisms are used, is the most common method to predict carcinogenicity in oil products. In some cases it gives a lower threshold value than the skin painting test. Analytical methods The molecules responsible for giving cancer are mainly the 3-7 ring aromatic in the oil. Analytical methods have been developed to measure the PAC content in the oil, IP 346, GCMS (Gas Chromatography Mass Spectrometer) and HPLC methods, etc. The only method that has been shown to correlate to the skin painting test is IP 346. The European Union has decided to use this method as a marker to predict carcinogenicity (oils with values less than 3% are not to be labelled as carcinogenic as of 1994). In other parts of the world other methods to predict carcinogenicity are discussed, e.g. the Ames test. Oils refined with old technology, such as acid clay treatment or only mild hydrofinishing, or when the oils have been subjected to discharges, the polycyclic content can be high. These kind of oils should therefore be handled with extra care and the proper precautions should be taken.
Nynas transformer oils are produced by severe hydrotreatment, yielding low PAC content. According to IP 346, the PAC content measured as DMSO extractable compounds of Nynas transformer oils is below 3%. The oils are labelled in conformity with EU regulations.
42
Oils for the future Today, Nynas Naphthenics have in their product portfolio a number of different oils with various properties and performances. These oils are used in different electrical equipment such as HVDC installations, power transformers, switch gears and distribution transformers, as well as cable oils. In the future, our opinion is that the basic line of transformer oils will consist of three grades: High grade, inhibited
(Nytro 10X)
Inhibited, with synthetic inhibitors having excellent electrical properties.
High grade, uninhibited (Nytro 10BN) Standard grade
Uninhibited, with high resistance to oxidation.
(Nytro 10 GBN) Higher aromatic content and therefore gas-absorbing.
As a supplier, we ourselves cannot develop or produce an oil for the future. What we have to do is to build up a knowledge of the chemical structure and of its effects on different properties. We also have to adapt our refining technology to a more efficient way of producing the oils. However, deciding what properties are important for the transformer is not our main task. That is something which you, as a customer, user or producer of transformers, have to decide. We will then be able to develop and produce tailor-made products with, hopefully, an acceptable cost/performance level.
43
REFERENCE LIST OF METHODS Listed below are the methods used in this handbook to characterise transformer oils. Some methods have several designations, the most common of which are mentioned here. In some cases comparable methods are listed, which are marked with an asterix. Please note that a comparable method might give a different value for the same characteristic.
Characteristics Density Kinematic viscosity
Designation 1 ISO 3675 ISO 3104
2 ASTM D 1298 ASTM D 445
3 IP 160 IP 71
Flash point (Closed cup) Pour point Interfacial tension Colour
ISO 2719 ISO 3016 ISO 6295 ASTM D 1500
ASTM D 93 ASTM D 97 ASTM D 971 IP 196
IP 34/304 IP 15
Corrosive sulphur Carbon type composition Carbon residue Water content Neutralization value
ISO 5662 IEC 590 ASTM D 189 IEC 814 IEC 296/82
ASTM D 1275 *ASTM D 2140 IP 13 ASTM D 1533 *ASTM D 974
BS 5680
Breakdown voltage AC Dielectric dissipation factor DC-resistivity Impulse breakdown Voltage Gassing tendency
IEC 156
BS 5874
*ASTM D 1816
IEC 247 IEC 247
BS 5737
*ASTM D 924
IEC 897 IEC 628 A
ASTM D 3300 BS 5797
IEC 1125 A IEC 1125 B IEC 1125 C DIN 51554 ASTM D 2112 ASTM D 2440
IEC 74 IEC 474 IEC 813
Oxidation stability:
44
*ASTM D 524 BS 6470 *IP 139
*ASTM D 2300 B
*Comparable methods
COMPARISON OF SOME REQUIREMENTS FOR CERTAIN SPECIFICATIONS. Characteristics
IEC 296 (Class II)
ASTM D 3487
BS 148/84
Density at 20 oC Viscosity at 40 oC mm2/s Viscosity at -30 oC mm2/s Pour point oC Flash point PM oC Flash point COC oC Neutralization value mg KOH/g Gassing properties µl/min Antioxidant content for uninhibited oils % Water content ppm Interfacial tension mN/m Breakdown voltage as delivered kV Treated kV Dielectric dissipation factor at 90 oC Oxidation stability
≤0.895 ≤11.0 ≤1800 ≤-45 ≥130
≤0.91 *5 ≤12.0
≤0.895 ≤11.0 ≤1800 ≤-45 ≥130
≤0.03 –
≤0.03 ≤30 *1
≤0.03 ≤5 *1
not detectable ≤30-≤40 *2
≤0.08 ≤35 ≥40
not detectable ≤30-≤40 *2 -
≥30 ≥50
– ≥70 *3
≥30 –
0.005 No
0.003 *4 comparable
0.005 requirement
≤-40 ≥145
*1 Not comparable figures. Given rather to indicate that there are requirements. *2 The lower level for bulk deliveries and the higher for drum deliveries. *3 Calculated to comparable figure. *4 At 100 °C *5 At 15°C
45
APPENDIX 1. BASIC CHEMISTRY OF TRANSFORMER OILS INTRODUCTION Before starting to discuss the refining of transformer oils, a basic understanding of the chemistry of the oil is needed. A mineral transformer oil consists mainly of carbon and hydrogen in molecules with different structures.
1. THE THREE LETTERS WHICH GIVE THE BASIC STRUCTURE OF A MINERAL TRANSFORMER OIL Paraffin
Isoparaffin
Basic hydrocarbon structures in mineral oil
Naphthenes
Aromatic
Figure 1
Polyaromatic
P for paraffinic structure. This group of molecules can either be straight
or branched. The straight type Normal-alkanes (N-alkanes) are known as waxes. If oils containing N-alkanes are cooled down, their free flow is impeded. Below the cloud point, these oils are non-Newtonian, and their N-alkane content has to be reduced before they can be used in a cold climate. Molecules of this type also have low solubility for water and oxidation products. This may cause problems in the form of precipitated sludge in the ducts of the transformer. Paraffinic molecules have lower thermal stability than naphthenic and aromatic molecules.
N
for naphthenic structure. The molecules in this group are also known as cycloalkanes. Characteristics: they have excellent low-temperature properties and better solvency power than N-alkanes. There are either 5, 6 or 7 carbons in the ring structure, but the 6 ring predominates.
46
A for
aromatic structure. All transformer oils contain aromatic molecules, and this is probably the most important group to discuss. The aromatic molecules contain at least one ring of six carbon atoms with alternating double and single bonds as their characteristic parts. They are totally different from paraffinic and naphthenic molecules, both chemically and physically.
2. INFLUENCE OF AROMATIC MOLECULES ON THE TRANSFORMER OIL PROPERTIES. Monoaromatics in transformer oils are always alkylated and generally have good electrical properties, as well as being gas-absorbents. They are relatively stable in oxidation. Polyaromatics, PACs, are either produced in the hydrogenation process or exist naturally in the oil. With increasing boiling range the PAC content is normally increased too. These groups have the following properties: DESIRABLE * Oxidation inhibiting: during the oxidation process, phenols are produced which act as a radical destruction inhibitor. In old transformer oils, phenols that have been produced as oxidation products can be measured. Compare this with DiButyl Para Cresol (DBPC), which is added to oils as an inhibitor. * High gas absorption, superior to that of monoaromatics. UNDESIRABLE * In an electrical field the aromatic molecules have a negative effect on such electrical properties as impulse breakdown and streaming charging. * Some of these molecules are known to be carcinogenic.
3. HYPOTHETICAL OIL MOLECULE Only polyaromatics and N-alkanes occur in oil as single molecules. All the others are combined into molecular structures of various kinds, the combination of the three letters give words of different meaning. The figure facing page illustrates a typical oil molecule. One way of characterising oils is by carbon type analysis. There are several methods for measuring carbon type, one of them being IR to measure the carbon bonded to the aromatic structure and the carbon bonded to the paraffinic structure.
47
= C in paraffinic structure CP = 32% = C in naphthenic structure CN = 44% = C in aromatic structure CA = 24%
Figure 2
4. HETEROATOMS IN THE OIL All oils contain a small percentage (by number) of hydrocarbon molecules, including in their structure other elements like nitrogen, sulphur and oxygen. Nearly all the heteroatoms in an oil are bonded to aromatic structures, and if all aromatics are removed by physical separation, all sulphur, nitrogen and oxygen are removed as well. Figure 3 Heteroatoms in mineral oil
X=S, N, O X Carbazol
Pyridin
N
Phenol
OH
4.1 Nitrogen Nitrogen-containing molecules can either be basic (e.g. quinolines, pyridines) or non-basic (e.g. carbazoles, pyrolles). The nitrogen content of transformer oils is relatively small (in the ppm range) but it makes a big difference to their characteristics. * Some of the nitrogen-containing molecules are charge carriers in an electrical field. * Some of them act as initiators of the oxidation process, and adding just a few ppm of a basic nitrogen containing molecules to an oil destroyed its oxidation stability. * Some of them act as passivators of copper or other metals. * Some act as inhibitors.
48
R
N H
R
R
R
N H
N
Pyrolles Carbazoles Non-basic nitrogen
N
Quinolines Pyridine Basic nitrogen
4.2 Sulphur The sulphur containing molecules in the oils can give both negative and positive characteristics to the oil. The sulphur containing molecules of some types can cause corrosion of copper and silver. They can also act as peroxide-destroying inhibitors in the oxidation process. One study which Nynas carried out showed that the more effective they were as inhibitors, the more reactive they were in copper corrosion. Hundreds of different types exist, but thiofens, carbazoles and sulphides can be found in mineral oils. Mercapto sulphur exists in unrefined oils but may also exist, as an intermediate oxidation product, in used transformer oils. Slightly oxidised transformer oils, therefore, may be corrosive to copper. As a rule, the sulphur content in a distillate (unrefined oil) increases with increasing boiling point.
4.3 Oxygen In new transformer oils the content of oxygen bound to hydrocarbons as heteromolecules is small. In used oils the bonded oxygen content is higher, due to oxidation in which acids, ketones, phenols and other oxygen containing molecules are formed. As stated earlier, the phenols may act as radically destroying inhibitors. Water is also an oxidation product. It is particularly destructive in oils and may cause the paper to deteriorate with excessive rapidity. Some of the above molecules are strongly polar and will be oriented in an electrical field giving field losses. Some of them may act as dispersing agents for water. The chemically bonded oxygen must not be confused with the physically dissolved oxygen gas. The latter can be removed by degassing.
5. VARIATION OF HYDROCARBON TYPES The content of the different types of hydrocarbons in an oil varies from one crude to another, and the resulting amount after refining varies from one process to another.
49
Figure 4
Variation in distillates, the raw material for production of transformer oil. Type
Amount
N-alkanes wt% CP (Carbon bonded paraffinic) by IR-method
<0.05-15% 42-65% *
CN (Carbon bonded naphthenic) by IR-method
difference to 100%
CA (Carbon bonded aromatic) by IR-method
14 - 25%
PAC HPLC%
>2 **
Sulphur wt%
1.0-2.0
Nitrogen ppm
70-600
Oxygen as hydrocarbon acids, expressed in
mgKOH/g
0.05-2.0
** Normally the level is so high that the feedstock has to be considered as carcinogenic. A higher boiling point gives a higher value. The HPLC method is described in the section on requirements for transformer oils. The difference between transformer oils and crude oils is that the former are categorised as »naphthenic oils« and the latter as »paraffinic oils«. However, there is no sharp distinction between the two types of oil, but rather a sliding scale that ranges from the very paraffinic to the very naphthenic. This characterisation is based on the IR measurement of the paraffinic content which is usually grouped as shown below. Oils with; *
CP 42-50% are considered as naphthenic oils
* *
CP 50-56% intermediate oils CP 56-65% paraffinic oils
The above levels are not exactly defined, but more intended as guidelines. Some hydrocracked oils have more than 65% in CP (not naturally occurring). Variation of hydrocarbon type composition in transformer oils depends on the feedstock, the processing type and degree, and also on the intended use of the oil: non-inhibited versus inhibited etc. Noninhibited oils normally have a higher PAC level as do gas-absorbing oils.
50
Below is a broad overview of the chemical composition of products existing on the market today.
Note that oils with these variations meet the normal standards existing today, but in service some of them will behave quite differently from what is expected. Type
Amount
N-alkanes wt% CP % by IR-method CN % “ CA % “ PAC HPLC % Sulphur % Nitrogen ppm Acid number
<0.1-10 42-65 difference to 100 % 5-20 0.02-2.5 0.01-1.0 1-300 <0.01-0.03
51
APPENDIX 2. REFINING TECHNIQUES Refining is the collective term for the processes, the refining steps, used to change the properties of mineral oils to desired ones. Basically these processes can be divided into physical and chemical ones, and full refining is normally a mixture of the two types of processes. Crude oil is the raw material from which transformer oil is produced. Crude oils are extracted in several different parts of the world, the best known being the North Sea, the Middle East and Venezuela. Crude oils can initially be divided into light and heavy types, but also into naphthenic and paraffinic types. The naphthenic crudes are normally rich in bitumen and heavy distillate, which also puts them in the heavy category.
Figure 1 Venezuelan crude oil
Heavy Arabian
North Sea
Heavy crude oil
1% 8%
15%
19%
32% 25%
25%
37% 13%
35%
72% Bitumen
Light gas oil
Heavy gas oil
Gasoline
18%
The paraffinic crudes, on the other hand, are often rich in gas oil, gasoline and gases, which puts them in the light category. The crude oil reserves for wax-free naphthenic oils are enormous, and new fields of naphthenic oil are still being found in various parts of the world. The selection of crude oil will depend on whether the refinery is a speciality producer or a fuel oil refinery. For most of the refineries, the lubricating oil sector is only a minor part of their activities. Only 1% of all products from crude oil are used as lubricating oils, which includes oils such as motor oils, process oils and transformer oils.
52
Figure 2 Products from crude oil
Segment process oil/base oil Fuel 96% Process oil/base oil 1%
➚
➚
· 90% Paraffinic process oil/base oil · 10% Naphthenic process oil/base oil
Bitumen 3%
1. REFINING To produce transformer oils from crude oil a number of sequences/steps are used, please see figure 3 below. In a typical “refining train” some of the steps described may be excluded due to type of oil and technique used. Figure 3
Distillation
Dewaxing
Extraction
Hydrogenation
2. DISTILLATION In a “refining train”, the first step is always distillation. In this process the crude oil is separated into distillates with different boiling point ranges by fractionation. For light crudes this is done under normal pressure, but for heavy crudes, or for further fractionation of heavy residues, the fractionation is done under vacuum conditions. Vacuum techniques will lower the boiling point for the hydrocarbons and allow fractionation of heavier molecules. The maximum temperature for fractionation is around +350 °C. Above this temperature thermal decomposition (cracking) of the oil will start. This process takes place in a fractionating tower and several distillates and a residue, normally bitumen, are produced at the same time and continuously. Different viscosities are obtained for different oils with a given boiling range, depending on their chemistry. Paraffinic oils have a higher boiling range for a given viscosity compared with a naphthenic. This is due to the higher mobility of a paraffinic molecule compared with a naphthe-
53
nic. For distillates from the same type of crude oil, there exists a rough correlation between the 50% point on the distillation curve and the viscosity. The flashpoint correlates with the beginning of the distillation curve, namely the 5% point. This applies to well-fractionated oils. Figure 4 Temp.
Temp. W.g? ?O.Yg? ?W20Y?g? W.M?h? ?W.Yhe? W.Y?he? ?O.Yhf? ?W20Y?hf? O.M?hg? O20Y ? O2@@0M ? ?O2@0M ? ?O2@@0M? ? O2@0M? ? ?O2@0M ? O2@0M? ? ?O2@0M ? O2@0M? ? W20M ? ?W.M ? O.Y? ? W20Y ? ?W.M ? W.Y? ? ?W.Y ? ?7H? ? J5 ? ?W.Y ? W.Y? ? 7H ? ?J5? ? W.Y? ? .Y ? ? ? ? ? ? ? ? ? ? ?
?O2@e ?O20M?e ?O20M?f ?O20M?g ?O20M?h O2@@@@@0M?he ?O2@@@@@@@0M ?O2@@@@0M? ?O2@@0M? ?O20M? ?O20M? ?O20M? ?O20M? ?O2@ @0M? O2@0M? O20Mf ?O2@0Mg O2@@@0M?h O2@@@@0Mhg ?O2@@@0M ?O2@@@@0M? ?O2@@0M? ?O20M? ?O20M? ?O20M? ?O20M? ?O2@ @0M? ?O20M? ?O20M?e ?O20M?f ?O20M?g ?O2@@@@@@0M?h ?O2@@@@@@0M? ?O2@@@@0M? ?O2@@0M? ?O20M? ?O20M? ?O20M? ?O20M? @0M? O2@? O20Me O20Mf O20Mg O20Mh ?O2@@@@@0Mhe O2@@@@@@@0M? O2@@@@0M O2@@0M O20M O20M O20M W20M .M
Crude
5
50
100
%
Dist. curve
5
50
The 5% point correlates with the flashpoint The 50% point correlates with the viscosity
100
%
Bitumen
3. DEWAXING Naphthenic crude contains hardly any N-alkanes and does not require a dewaxing step, but for paraffinic crudes dewaxing is necessary in order to achieve reasonable low temperature properties. Traditional dewaxing cannot remove all waxes from an oil. There will always be waxes below the dewaxing point chosen. The principle for this process is to blend the oil with a solvent and then cool it down. The N-alkanes are then allowed to crystallise into long needles and the wax is removed by filtration. After filtration, the solvent is removed from the oil by distillation. Some refiners are equipped for “deep dewaxing”, giving -30 °C as pour point, but below this point the oil will still be solid. Other refiners use higher temperatures in their process and use pour point depressants to compensate the higher temperature and to reduce the pour point. These pour point depressants can either be of the esther type or the hydrocarbon type. Figure 5
Solvent
Solvent Feed
Oil
Filter Oil
Oil Blending
Cooling and formation of wax crystals
Separation
Wax
54
Pour point Feed +20°C Product -15°C
Separation of N-paraffins from the oil by use of a solvent and then cooling the blend and filtering of the wax.
4. EXTRACTION The extraction step is one of the oldest methods of removing unstable molecules from the distillates, and it is still in use. In this process the oil is blended with a solvent (e.g. SO2 or furfural). The mix separates into a raffinate phase and an extract phase rich in aromatic and heteroaromatic molecules. The amount of aromatics in the raffinate phase is between 5 and 11%. It is hard to achieve less or more than this, it is depending on the equilibrium between the two phases. Most of the polyaromatic molecules (PAC) are found in the extract phase. The following table shows individual PACs in two different extracts. Both these extracts are now considered carcinogenic and have to be labelled with the skull and crossbones. Type
OIL A
OIL B
Phenanthrene Anthracene Benzo(b) fluorene Benzo(b,j,k) fluoranthene Perylene
2300 89 29 0.5 <0.5
250 29 6.3 8.1 6.4
Individual PAC ppm The above figures provide some indication of the types of PACs occurring in low-refined oils. Extract A is a normal extract from a naphthenic distillate. Extract B is from a higher boiling fraction. These figures also illustrates that when the boiling point increases, the number of rings in the PACs also increases. Due to labelling requirements and high sulphur content, the alternative commercial value for these streams is lower today than it was some years ago. Figure 6 Solvent Solvent
Raffinate
D = Distillate R = Raffinate E = Extract
Dist
D Mixing Oil
R
Extract Dist
E
55
CA% 20-25 5-12 >40
Extraction. Aromatic compounds are removed by the use of a polar solvent: sulphur dioxide, furfural etc.
5. ACID CLAY TREATMENT Sulphuric acid is the most versatile refining agent known. This acid acts both as an extraction medium and as a reactive agent, depending on temperature and concentration. Oleum is still used in some countries for producing white oils, but it is steadily being superseded by hydrogenation. White oils are totally free from aromatics and heteroatoms. After the process, the excessive acid has to be neutralised, normally with lime or soda. Acid clay treatment is an obsolete process today, due mainly to the environmental impact of its waste products. Activated clay is still used as a final finishing to remove trace impurities which are adsorbed on the clay surface. The amount of clay used for this finishing is low.
6. HYDROGENATION The above techniques (extraction and dewaxing) are based on methods: i.e. separating off unwanted molecules. A more method, hydrogenation, is based on the chemical conversion molecules into desired ones. This is done with the help of a hydrogen and high pressure/temperature.
physical modern of these catalyst,
Figure 7 CA % 20-25
X
H2
X H.
H.
H.
H.
CATALYST
MEDIUM SEVERITY
CA 25% feed
X . . . H. H H H H. H. H.
H.
H2
CA % 2-17
X H. H. H. H. H. H. HIGH SEVERITY
CATALYST
Light products, H2S, NH3, H2O
In the hydrogenation process, polar compounds, aromatics, hetero-atomic molecules are adsorbed on a catalyst surface, where they react with the hydrogen “dissolved” in the catalyst. The catalyst itself can be described as a porous inert mineral impregnated with catalytically active metals which adsorb polar molecules and favour their reaction with absorbed hydrogen. The catalytically active surface area is very large (up to 200 m2/gram catalyst). At low severity, low pressure/low temperature and high space velocity, only sulphur, oxygen and nitrogen will be removed as H2S, H2O and NH3.
56
Hydrogenation process. X = S, N, O.
When the severity is increased, the aromatic rings are opened and saturated; exactly how much depends on the degree of severity. The reaction sequence depends on polarity, i.e. polyaromatics are reduced first, leaving monoaromatics in the oil. If a more acidic type of catalyst is used, more cracking will take place, giving more light products, e.g. gas oils and gasoline. This type of catalyst is not used by the lube producers. The light ends and other products produced in the hydrogenation process are removed from the oil afterwards by stripping/distillation. The H2S from the process is converted into pure sulphur in a Claus unit. This makes the hydrogenation process an environment-friendly process with a high yield of product and a small amount of waste products. Its disadvantage is the high investment cost.
Nynas development of refining technology Nynas has been producing transformer oils for more than 50 years. By refining from low-wax crude oils, no dewaxing step is required in our refining train. The company began as a traditional oil company producing products of all kinds – fuel, lubes and bitumen. In 1982, it was decided that Nynas should concentrate on two products – bitumen and speciality oils (of which transformer oils is one). The first refining process used was SO2 extraction, using acid clay as the final step. The clay treatment was discontinued in 1975, for several reasons: the cost/yield ratio and, above all, environmental considerations: the acid/clay resulting from the process is considered as toxic waste. In 1975 Nynas invested in the first hydrogenation unit, and in 1988 in a second one operating at high pressure. Today hydrogenation as final stop accounts for 100% of total production. A small clay unit is still used for polishing speciality products.
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Development of Nynas refining technology Figure 8 Acid refined
➞ 1975
Solvent refined Vacuumdistillation
Extraction
Acid/Clay
Medium/Highly refined
1975 ➞
Solvent refined oil Vacuumdistillation
Extraction
Hydrogenation
Highly refined
Vacuumdistillation
1988 ➞
Hydrogenation
This handbook is for information and reference purposes only. Nynäs Naphthenics AB extends no guarantees, warranties or representation of any kind expressed or implied with respect to quality or to fitness or suitability for any use of any products/methods mentioned in this handbook. The terms and conditions for the suitability and quality of a specific product bought from Nynäs Naphthenics AB by a customer will be exclusively as stated in the separate sales agreement for such product.
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Responsible Care Nynas is a signatory to the international Responsible Care programme of the CEFIC (European Chemical Industry Federation). The programme is the chemical industry’s commitment to continuous improvement in all aspects of health, safety and environmental protection. Responsible Care is a voluntary initiative, fundamental to the industry’s present and future performance and a key to regaining public confidence and maintaining acceptability. The signatories pledge that their companies will make health, safety and environmental performance an integral part of overall business policy on all levels within their organizations.
SALES OFFICES Australia & New Zealand Nynas (Australia) Pty Ltd. One Park Road, Milton, QLD 4064, Brisbane, Australia Tel: +61 7 387 66 944. Fax: +61 7 387 66 480 Belgium Nynas N.V., Haven 281, Beliweg 22, BE-2030 Antwerp Tel: +32 3 545 68 11. Fax: +32 3 541 36 01 Brazil Nynas Do Brasil LTDA, Rua Jesuíno Arruda 676, 9th Floor cj. 91, Itaim Bibi, São Paulo, SP 04532-082 Tel: +55 11 3078-1399. Fax: +55 11 3167-5537 Canada Nynas Canada Inc., Suite 610, 201 City Centre Drive, Mississauga, Ontario, Canada L5B 2T4 Tel: +1 905 804-8540. Fax: +1 905 804-8543 China Nynas (Hong Kong) Ltd. Beijing, Room 703C, Huapu International Plaza No. 19 Chaoyangmenwai Street, Beijing, 100020 Tel: +86-10-6599 26 95. Fax: +86-10-6599 26 94 Colombia Nynas Naphthenics, Planta Algranel, Antiguo Puente de Bazurto, Manga, Cartagena Tel.: +57 5660 7850. Fax: +57 5660 8755 France Nynas S.A., Le Windows, 19 Rue d’Estienne d’Orves, F-93500 Pantin Tel: +33 1 48 91 69 38. Fax: +33 1 48 91 66 93 Germany Nynas GmbH, Berliner Allee 26, D-40212 Düsseldorf Tel: +49 211 828 999 0. Fax: +49 211 828 999 99 Great Britain Nynas Naphthenics Ltd, Wallis House, 76 North Street, Guildford, Surrey, GU1 4AW Tel: +44 1483 50 69 53. Fax: +44 1483 50 69 54 Hong Kong Nynas (Hong Kong) Ltd, 1301 Chinachem Johnston Plaza, 178-186 Johnston Road, Wanchai Tel: +852 2591 99 86. Fax: +852 2591 49 19. Italy Nynas S.r.l., Via Teglio 9, I-20158 Milan Tel: +39 02 607 01 87. Fax: +39 02 688 48 20 Malaysia Nynas (Hong Kong) Ltd Rep Office, No. 302, Block A, Kelana Center Point No. 3, Jalan SS7/19, Kelana Jaya, 47301 Petaling Jaya, Selangor Tel: +603 7880 9336. Fax: +603 7880 9366 Mexico Nynas Mexico S.A. Emerson 150, 801 & 802, Col. Polanco D.F. 11560, Mexico City Tel: +52 5 545 38 70. Fax: +52 5 25 00 930 Middle East Nynas Naphthenics, Al Jumeira Road, Arenco 34 Jumeira, 14th Street, Villa No. 27, Dubai, U.A.E. Tel: 97 150 551 76 88 . Fax: +97 1 43 49 32 81 Poland Nynas Sp. z.o.o., Ul. Toszecka 101, 44-100 Gliwice Tel: +48 32 232 74 10. Fax: +48 32 279 28 50 Scandinavia Nynäs Naphthenics AB Norden, P.O. Box 10701, S-121 29 Stockholm Tel: +46 8 602 12 00. Fax: +46 8 81 20 12
Spain Nynas Petróleo S.A., Garcia de Paredes 86 1°A, ES-28010 Madrid Tel: +34 91 702 18 75. Fax: +34 91 702 18 81 Turkey Nynas Naphthenics Yaglari Tic. Ltd. Sti. Kantaciriza Sokak 15/3, 81070 Erenköy, Istanbul Tel: +90 216 368 38 42. Fax: +90 216 368 37 48 Central- and Eastern Europe / Latin America Nynäs Naphthenics AB, Box 10701, S-121 29 Stockholm, Sweden Tel: + 46 8 602 12 00. Fax: + 46 8 508 665 10 RESEARCH & DEVELOPMENT Nynäs Naphthenics AB, S-149 82 Nynäshamn, Sweden Tel: +46 8 520 65 000. Fax: +46 8 520 20 743
www.nynas.com/naphthenics
newton/ab stjärntryck, Stockholm, Sweden 10.2001
South Africa Nynas South Africa (PTY) Ltd, Gatesview House A3, Constantia Park Cnr 14th Avenue and Hendrik Potgieter Street Weltevreden Park Tel: +27 11 675 1774. Fax: + 27 11 675 1778
