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Power-frequency overvoltage tests
The traditional approach towards demonstrating that insulation will not be broken down by the applied voltage has been to apply a test voltage which is very much greater than that likely to be seen in service. This is the philosophy behind the overpotential test, described above, which involves the application of twice normal voltage. Traditionally this was applied for 1 minute, but EN 60076 now allows this to be for a period of 120 times the rated frequency divided by the test frequency (in seconds), or 15 seconds, whichever is the greater. The test frequency is increased to at least twice the nominal frequency for the transformer to avoid over fluxing of the core and is often of the order of 400 Hz, so that test times of 15-20 seconds are the norm. As explained above, this test is thought by many to be a very crude one akin to striking a test specimen with a very large hammer and observing whether or not it breaks.
Considerable thought has therefore been applied in recent times in many quarters to improving this test and this was the process which brought about the introduction of partial discharge measurements during the application of over voltage as described for the AC long duration induced overvoltage test in the previous section. However, in the CEGB at that time it was not considered that the degree of overvoltage to be applied should be reduced in the way this was done for the standard BS induced overpotential test. At a time of recognizing poor transformer reliability it does not seem appropriate to reduce test levels. In addition, as has been indicated above, it was not felt that sufficient was known about the levels of partial discharge which might be indicative of possible pre mature failure. In fact, it has proved to be the case that some manufacturers designs regularly achieve very much lower partial discharge levels than those of other manufacturers so the establishment of acceptance/rejection limits would be very difficult. Hence it was decided to retain the existing overpotential test levels but to specify the monitoring of partial discharge as a means of learning as much as possible from the induced overvoltage test.
Discharge measurements were made at the HV terminal of the winding under test during the raising and the lowering of the voltage. These were recorded at 1.2 and 1.6 times nominal working voltage to earth. At the time that this test method was developed, CEGB engineers favored the measurement of radio interference voltage (RIV), measured in microvolts, as a convenient means of detecting and quantifying partial discharge. This method has since tended to have been dropped in favor of the system described earlier, which, it is claimed, is absolute in that it gives a value in picocoulombs which is indicative of the actual quantity of discharge which is taking place. Unfortunately there is no simple relationship between microvolts and picocoulombs. CEGB specified that for their test the RIV measured at 1.2 times nominal volts should not exceed 100 µV including background. Background was to be measured before and after the test and was not to exceed 25 µV. The figure of 100 µV was recognized as not a very exacting one. Should this be exceeded at only 1.2 times nominal volts it was considered that there would be little doubt that all was not well with some part of the insulation structure.
Very occasionally, partial discharge measurements made in this way can give a warning preceding total failure and the test voltage can be removed before complete breakdown, thus avoiding extensive damage. More often, however, the diagnosis is less clear-cut. It could be that measurements taken as the test voltage is being reduced indicate a tendency towards hysteresis, that is, the discharge values for falling voltage tend to be greater than those measured as the voltage was increased. This could indicate that application of the test voltage has caused damage. As the overvoltage is reduced, the discharge should fall to a low level, ideally considerably less than the specified 100 µV, by the time the voltage has fallen to a safe margin above the normal working level, hence the specification of the value at 1.2 times normal volts. During the 13 years of the author's involvement with this means of testing, up to the end of the CEGB's existence upon privatization, only one unit is on record as having been rejected on test on the strength of this partial discharge measurement alone. Much more numerous were the occasions on which manufacturers withdrew units from test in order to investigate high levels of partial discharge occurring at voltages much nearer to the full overpotential level.
A further point to be noted is that, whilst the induced overvoltage test is usually thought of as a 'twice normal voltage' test, for very high-voltage transformers with non-uniform insulation, the way it was customarily carried out in the UK it can be even more severe than this. FIG. 42(a) shows the arrangement for carrying out the induced overvoltage test on a 400 kV transformer having non-uniform insulation on the star-connected HV winding and a delta connected LV winding. The test supply is taken from a single-phase generator connected to each phase of the LV in turn. The diagram shows the arrangement for testing phase A. In accordance with the then current BS 171, Clause 11.3 and Table IV (and included in Table 1 of this section), a voltage of 630 kV to earth must be induced at the line terminal. BS 171 did not specify on which tap ping the transformer should be connected and so the manufacturer usually opted for position 1 which corresponds to maximum turns in circuit in the HV winding. This might be the _6.66 percent tap for a generator transformer, which could correspond to 460.5 kV for a transformer having an open-circuit voltage of 432 kV on the principal tap. This is the line voltage, so the phase voltage appropriate to position 1 is 460.5/_3 _ 265.8 kV: the test voltage of 630 kV induced in this winding therefore represents 2.37 times the normal volts/turn.
The necessity for carrying out the test as described above arises because of the need to retain the neutral connection to earth due to the very modest test level specified for the neutral when non-uniform insulation is used (BS 171, Clause 5.5.2 specified 38 kV test, CEGB practice was to specify 45 kV). If the voltage on the neutral can be allowed to rise to about one-third of the specified test level for the line terminal then the minimum test requirements can be met by carrying out the test using the arrangement shown in FIG. 42(b). With this arrangement the neutral earth connection is removed and the line terminals of the two phases not being tested are connected to earth. An induced voltage of exactly twice normal volts for a 400 kV transformer would result in a minimum voltage of 420 kV in the phase under test on any tapping higher than _9 percent with the neutral being raised to 210 kV, and the line terminal of the phase under test is raised to 630 kV as specified.
The test voltage of 210 kV for the neutral is, of course, rather high to obtain the full benefit of non-uniform insulation, so the advantage to be gained from this test method for 400 kV transformers might not be considered worthwhile, however, for 132 kV transformers tested at 230 kV the neutral will be raised to a more modest 77 kV. At this level, the neutral is unlikely to need more insulation than that which would be required for mechanical integrity, except possibly a higher-voltage class of neutral terminal and it is possible to install a suitable terminal on a temporary basis simply for the purpose of carrying out the induced overvoltage test.
Choice as to the method of carrying out the induced overvoltage test ultimately resides with the purchaser of the transformer. Clearly, if the customer considers that high integrity and long life expectancy are his priorities then a test method which involves the application of 2.4 times normal voltage is likely to be more attractive than one at a mere twice normal.
It will be seen from FIG. 42(a) that during the induced overvoltage test, although all parts of the windings experience a voltage of more than twice that which normally appears between them, that section of the winding which is nearest to earth is not subjected to a very high voltage to earth. This is so even for fully insulated windings which, when tested, must have some point tied to earth. It is therefore necessary to carry out a test of the insulation to earth (usually termed 'major insulation' to distinguish this from interturn insulation) and, for a fully insulated winding, this is usually tested at about twice normal volts. For a winding having non-uniform insulation, the test is at some nominal voltage; for example, for 400, 275 and 132 kV transformers, it is specified as 38 kV in BS 171.
In addition to partial discharge measurement, another diagnostic technique for detection of incipient failure introduced by CEGB has in recent years become increasingly recognized: this is the detection and analysis of dissolved gases in the transformer oil. This was initially regarded as applicable only to transformers in service. When partial discharge or flashover or excessive heating takes place in transformer oil, the oil breaks down into hydrocarbon gases.
The actual gases produced and their relative ratios are dependent on the temperature reached. This forms the basis of the dissolved-gas analysis technique which is described in greater depth in Section 6.7. When faults occur during works tests, the volumes of the gases produced are very small and these diffuse through very large quantities of oil. Although the starting condition of the oil is known and its purity is very high, very careful sampling and accurate analysis of the oil are necessary to detect these gases. Analysis is assisted if the time for the test can be made as long as possible, and this was the philosophy behind the 3 hour overpotential test which was introduced by the CEGB in the early 1970s as another of the measures aimed at improving generator transformer reliability. It must be emphasized that this test is carried out in addition to the 'twice normal volts' test; 130 percent of normal volts is induced for a period of 3 hours. In order that the magnetic circuit, as well as the windings, receives some degree of overstressing, the test frequency is increased only to 60 Hz rather than the 65 Hz which would be necessary to prevent any overfluxing of the core. Partial discharge levels are also monitored throughout the 3 hours.
Oil samples for dissolved-gas analysis are taken before the test, at the midway stage and at the conclusion.
Impulse tests differ from power-frequency tests in that, although very large test currents flow, they do so only for a very short time. The power level is there fore quite low and the damage done in the event of a failure is relatively slight.
If a manufacturer suspects that a transformer has a fault, say from the measurement of high partial discharge during the overpotential test, he may prefer to withdraw the transformer from this test and apply an impulse test which, if an insulation fault is present, will produce a less damaging breakdown. On the other hand, the very fact that damage tends to be slight can make the location of an impulse test failure exceedingly difficult. Diagnosis of impulse test failures can themselves be difficult, since sometimes only very slight changes in the record traces are produced. For further information on impulse testing and diagnosis techniques the reader is referred to IEC 60076-4 'Guide to the lightning impulse and switching impulse testing - power transformers and reactors' or any other standard textbook on the subject.
The second possible mode of transformer failure identified earlier in this section is premature ageing of insulation due to overheating. It was therefore considered important that the opportunity should be taken to investigate the thermal performance of the transformer during works testing as fully as possible, in an attempt to try to ensure that no overheating will be present during the normal service operating condition.
Conventional temperature rise tests, for example, in accordance with EN 60076-2, are less than ideal in two respects:
(1) They only measure average temperature rises of oil and windings.
(2) By reducing the cooling during the heat-up period, manufacturers can shorten the time for the test to as little as 8 or 10 hours.
Such tests will have little chance of identifying localized hot spots which might be due to a concentration of leakage flux or an area of the winding which has been starved of cooling oil. The CEGB approach to searching out such possible problems was to subject the transformer to a run during which it should carry a modest degree of overcurrent for about 30 hours. The test was specified as a period at 110 percent full-load current, or a current equivalent to full-load losses supplied, whichever is the greater, for 12 hours at each extreme tap position, with each 12 hours commencing from the time at which it reaches nor mal working temperature. Also, during this load-current run, the opportunity can be taken to monitor tank temperatures, particularly in the vicinity of heavy flanges, cable boxes and bushing pockets, and heavy current bushings. Both extremes of the tapping range are specified since the leakage flux pattern, and therefore the stray loss pattern, is likely to vary with the amount and/or sense of tapping winding in circuit. Oil samples for dissolved-gas analysis are taken before the test and at the conclusion of each 12-hour run as a further aid to identification of any small areas of localized overheating. If the transformer is the first of a new design, then gradients, top oil and resistance rises can be measured in accordance with the specified temperature rise test procedure of EN 66076-2. However, the main purpose of the test is not to check the guarantees, but to uncover evidence of any areas of overheating should these exist.
It is in relation to short-circuit performance and the demonstration that a transformer has adequate mechanical strength that the customer is in the weakest position. Yet this is the third common cause of failure listed at the beginning of this section. Section 4.7 of describes the nature of the mechanical short-circuit forces and makes an estimate of their magnitude. However, for all but the smallest transformers, the performance of practical tests is difficult due to the enormous rating of test plant that would be required. EN 60076, Part 5, deals with the subject of ability to withstand both thermal and mechanical effects of short circuit. This it does under the separate headings of thermal and dynamic ability.
For thermal ability, the method of deriving the r.m.s value of the symmetrical short-circuit current is defined, as is the time for which this is required to be carried, and the maximum permissible value of average winding temperature permitted after short circuit (dependent on the insulation class). The method of calculating this temperature for a given transformer is also defined.
Thus this requirement is proved entirely by calculation.
For the latter, it is stated that the dynamic ability to withstand short circuit can only be demonstrated by testing; however, it is acknowledged that transformers over 40 MVA cannot generally be tested. A procedure for testing transformers below this rating involving the actual application of a short circuit is described. Oscillographic records of voltage and current are taken for each application of the short circuit and the assessment of the test results involves an examination of these, as well as an examination of the core and windings after removal from the tank. The Buchholz relay, if fitted, is checked for any gas collection. Final assessment on whether the test has been withstood is based on a comparison of impedance measurements taken before and after the tests. It is suggested that a change of more than 2 percent in the measured values of impedance are indicative of possible failure.
This leaves a large group of transformers which cannot be tested. Although this is not very satisfactory, service experience with these larger transformers over a considerable period of time has tended to confirm that design calculations of the type described in the previous section are producing fairly accurate results. Careful examination of service failures of large transformers, especially where there may be a suspicion that short circuits have occurred close to the transformer terminals, can yield valuable information concerning mechanical strength as well as highlighting specific weaknesses and giving indication where weaknesses may be expected in other similar designs of transformer. For large important transformers which cannot be tested for short-circuit strength, there is no better method of assessing their capability than carrying out a critical review of manufacturers' design calculations questioning the assumptions made and seeking reassurance that these follow the manufacturers' own established practices proven in service. Where, by virtue of extending designs beyond previously proven ratings, it is necessary to make extrapolation, then such extrapolation should be clearly identified and the basis for this fully understood.
4. TRANSPORT, INSTALLATION AND COMMISSIONING
Generator transformers and 400 kV interbus transformers are amongst the largest and heaviest single loads to be transported. In the UK, unlike in the case of many of the countries of continental Europe, these are invariably transported by road. Transport considerations will therefore have a considerable bearing on their design and more will be said on this aspect in the sections dealing specifically with these transformers in Section 7. For many other large transformers (grid bulk-supplies transformers, power station and unit transformers, primary distribution transformers), it is usually only necessary to ship these without oil to ensure that they are comfortably within the appropriate transport limits, although it is necessary to check that when mounted on the transport vehicle the height is within the over-bridge clearances which, for trunk roads within the UK, allows a maximum travelling height of 4.87 m (16 ft).
In recent years in the UK, the road transport authorities have become very much less tolerant of the disruption caused by the transport of heavy loads by road, so that there has been insistence on shipment by sea to a location as near to the final destination as possible, even if this results in a very much more arduous journey than that which would be experienced if travelling were by road.
In many parts of Europe and in the USA transportation by rail is a regular practice. This form of transport can impose much greater shock loadings on the transformer active parts, and particularly the core and its supporting structure, than would be expected to result from transport by road. Horizontal and vertical impacts can result from this type of transportation as well as yawing and swaying of the transport carriage. It is generally considered that it is necessary to design for vertical and horizontal accelerations of up to 4 g to safely withstand this mode of transportation.
Since the market for large transformers has become a global one, many large units can also be subjected to the rigors of long sea voyages for which peak accelerations might generally be considered to be very much less than the values for rail transport identified above, but these do require the design of the support structure for the active parts to take account of the repetitive nature of the accelerations resulting from rolling, pitching and heave that might be experienced for extended periods in rough sea conditions. Instances are on record of severe dam age having been caused to transformer active parts as a result of sea voyages in which no acceleration greater than 1 g has been experienced.
From all of the foregoing it will be apparent that no unit larger than, say, 10 MVA should be transported without the use of suitable accelerometers to ensure that no shock loadings approaching the design basis loading are experienced during shipment. Such devices should be set to record individual shocks greater than 1 g and, in the case of sea voyages, consideration should be given to the fitting of additional devices to summate the number of lesser shocks, of, say, 0.7 g. Following off-loading at the destination no work should be carried out in preparation for erection of the unit until these records are downloaded and assessed.
In the USA a Guide for the Transportation of Transformers and Reactors Rated 10,000 kVA or Larger has been in preparation since 2005. When published, this will be IEEE Standard C57.150.
If the tank has been drained for transport, it is necessary for the oil to be replaced by either dry air or nitrogen, which must then be maintained at a slight positive pressure above the outside atmosphere to ensure that the windings remain as dry as possible whilst the oil is absent. This is usually arranged by fitting a high-pressure gas cylinder with a reducing valve to one of the tank filter valves and setting this to produce a slow gas-flow sufficient to make good the leakage from the tank flanges. A spare cylinder is usually carried to ensure continuity of supply should the first cylinder become exhausted.
Transporters for the larger transformers consist of two beams which span front and rear bogies and allow the tank to sit between them resting on plat forms which project from the sides of the tank. Thus the maximum travelling height is the height of the tank itself plus the necessary ground clearance (usually taken to be 75 mm but capable of reduction for low bridges). FIG. 43 shows a 267 MVA single-phase transformer arranged for transport.
Smaller transformers, that is, primary distribution transformers having ratings of up to 30 MVA, can usually be shipped completely erected and full of oil.
Installation and site erection
In view of their size and weight, most transformers present special handling problems on site. The manufacturer in his works will have crane capacity, possibly capable of lifting up to 260 tonnes based on transport weight limit including vehicle of 400 tons, the normally permitted maximum for UK roads, but on site such lifts are out of the question except in the turbine hall of a power station where a permanent crane will probably have been installed for lifting the generator stator and rotor. Site handling is therefore difficult and must be restricted to the absolute minimum. The transformer plinth should be completed and clear access available, allowing the main tank to be placed directly onto it when it arrives on site. A good access road must also be available, as well as the surface over any space between access road and plinth. Transformer and vehicle can then be brought to a position adjacent to the plinth. The load is then taken on jacks and the transport beams removed.
Then, using a system of packers and jacks, the tank is lowered onto a pair of greased rails along which it can be slid to its position over the plinth. The required position of the tank on the plinth must be accurately marked, particularly if the transformer is to mate up with metal clad connections on either the LV or HV side.
When the tank is correctly positioned on the plinth it must then be carefully examined for any signs of damage or any other indication that it might have been mishandled during transport. If accelerometers (impact recorders) have been fitted for transport, these should be read, or downloaded if of the micro processor type, and then switched off and removed. Any special provisions by way of protection applied during transport must be removed. If additional clamping has been applied to the core and windings for transport, this must be released or removed according to the instruction manual. The coolers and pipework, if they have been removed for transport, are installed. Bushings and turrets which will probably also have been removed for transport are fitted and connected, requiring the removal of blanking plates giving access to the tank. Such opening of the tank must be kept to a minimum time, to reduce the possibility of moisture entering the tank; to assist in this, manufacturers of large high-voltage transformers provide equipment to blow dry air into the tank and thus maintain a positive internal pressure. If the transformer has been transported with the tank full of nitrogen, it is necessary to purge this fully with dry air if anyone has to enter the tank.
When all bushings have been fitted, access covers replaced, and conservator and Buchholz pipework erected, any cooler bank erected and associated pipework installed or tank-mounted radiators fitted, preparations can begin for filling with oil. Even if the transformer is not required for service for some months, it is desirable that it should be filled with oil as soon as possible and certainly within 3 months of the original date of draining the oil in the factory.
If it is being kept in storage for a period longer than 3 months at some location other than its final position, it should similarly be filled with oil.
Oil filling and preparation for service
The degree of complexity of the preparation for service depends on the size and voltage class of the unit. Modern 400 kV transformers, and to a slightly lesser extent those for 275 kV, are designed and constructed to very close tolerances. The materials used in their construction are highly stressed both electrically and mechanically, and to achieve satisfactory operation extensive precautions are taken in manufacture, particularly in respect of insulation quality. This quality is achieved by careful processing involving extended vacuum treatment to remove moisture and air followed by filling with high-quality oil as described in the previous section. Treatment on site must be to a standard which will ensure that the same high quality of insulation is maintained.
One hundred and thirty-two kV transformers and those for lower voltages generally do not require the same high processing standards and in the following description, which is related to the highest-voltage class of transformers, an indication will be given of where procedures may be simplified for lower-voltage units.
After completion of site erection, a vacuum pump is applied to the tank and the air exhausted until a vacuum equivalent to between 5 and 10 mbar can be maintained. If this work is carried out by the transformer manufacturer, or his appointed subcontractor, there will be no doubt as to the ability of the tank to withstand the applied vacuum. In all other cases the manufacturer's instruction manuals must be consulted as to permitted vacuum withstand capability. Some transformer tanks are designed to have additional external stiffeners fitted to enable them to withstand the vacuum. If this is the case a check should be made to ensure that these are in place. If the transformer has an externally mounted tapchanger it is likely that the barrier board separating this from the main tank will not withstand the vacuum. Any manufacturer's instructions for equalizing the pressure across this board must also be noted and carefully observed. For transformers rated at 132 kV and it below it is likely that the vacuum withstand capability of the tank will be no more than 330 mbar absolute pressure.
When a new 400 kV transformer is processed in the factory as described in the previous section, the aim is to obtain a moisture content in the cellulose insulation of less than 0.5 percent. When an oiled cellulose insulation is exposed to atmosphere, the rate of absorption of moisture depends on the relative humidity of the atmosphere, and a general objective of manufacturers of 400 kV transformers is that insulation should not be exposed for more than 24 hours at a humidity of 35 percent or less. Pro rata this would be 12 hours at 70 percent relative humidity. During this time the moisture would be absorbed by the outer surfaces of the insulation; increased exposure time causing gradual migration of the moisture into the inner layers. It is relatively easy, if a sufficiently high vacuum is applied, to remove moisture from the outer surfaces of the insulation, even if the outer surface content may be as high as 10 percent.
However, once moisture has commenced migration into the intermediary layers of the insulation, although a high vacuum would quickly dry the outer layers, time is then required at the highest-vacuum attainable to pull the moisture from the inner layers to the surface and out of the insulation. It must be noted also that on exposure, air is being absorbed into the oil soaked insulation at an equivalent rate to the moisture absorption, and that any air voids remaining after oil filling and processing could initiate partial discharges and subsequent breakdown. This is the reason for the recommendation, given above, that if the transformer is to be put into storage, it should not be left without oil for a period longer than 3 months. Whilst left without oil, even if filled with dry air or nitrogen, that oil which remained in the windings initially will slowly drain out of these, leaving voids which will require many hours of high vacuum to remove the gas from them to be replaced by the oil when the transformer is finally filled.
Provided the appropriate procedures have been observed during the site erection, the amount of moisture entering the insulation during the period of site erection will have been small and its penetration will largely have been restricted to the outer layers. However, even then, the length of time required for the maintenance of vacuum is not easily determined, and, if possible, the manufacturer's recommendations should be sought and followed. A vacuum of 5 mbar should be maintained for at least 6 hours before oil filling, many authorities would suggest a figure of not less than 12 hours.
Heated, degassed and filtered oil is then slowly admitted to the bottom of the tank in the same way as was done in the works, until the tank is full. Since, despite all the precautions taken, some moisture will undoubtedly have entered the tank during site erection, the oil must then be circulated, heated and filtered until a moisture content of around 2 p.p.m. by volume is achieved for a 400 or 275 kV transformer. For other transformers having a high voltage of not greater than 132 kV, a figure of around 10 p.p.m. is acceptable. More will be said about moisture levels in oil and insulation.
If the windings have been exposed for a period of longer than 24 hours, or if there is any other reason to suspect that the insulation dryness obtained in the factory has been lost, for example loss of the positive internal pressure during shipment, then it is necessary to dry the unit out. Without the facilities which are available in the factory, this will be a very difficult and time-consuming process. The drying-out process is greatly assisted by any heating which can be applied to the windings and major insulation.
Drying out on site
Oil companies, transformer manufacturers and supply authorities have mobile
filter plants and test equipment available to undertake the filling of transformers and any subsequent treatment. Modern practice for the drying of both oil and transformers tends to employ the method in which oil is circulated under vacuum in the oil treatment plant.
Heating, in addition to that supplied by the mobile plant, can be obtained by the application of short-circuit current and can be conserved by the use of lagging such as wagon sheets, sacking or other suitable material.
The temperature is controlled by thermostats incorporated in the mobile treatment plant heaters so that the oil cannot be overheated even in the event of any inadvertent reduction in flow. Interlocking systems control flows and levels to prevent flooding or voiding in either tank or plant.
The treatment units supplied by the oil companies usually incorporate a fully equipped laboratory manned by a chemist and capable of testing oil for electric strength, dielectric dissipation factor, resistivity, water content and air content as a routine. Other tests can be carried out if deemed necessary. The results of these tests carried out in a pattern according to the transformer to be processed can be plotted to show how the drying process is proceeding and its satisfactory completion.
Other tests, normally carried out by the electrical engineer, should include (a) insulation resistance between HV and LV windings and between each winding and earthed metal, and (b) temperature. These plotted with insulation resistance and also temperature as ordinates, against time as abscissae, give an indication of the progress of the drying-out operation.
There are three stages in the complete process. First, the heating-up stage when the temperature is increasing from ambient to the recommended maximum for drying out and the insulation resistance of the windings is falling. Second, the longest and real drying period when the temperature is maintained at a constant level with the insulation resistance also becoming constant for a period followed by an increase indicating that nearly all the moisture has been removed.
Third, the cooling period, with the heating and circulation stopped, during which the normal equilibrium condition of the transformer is restored, with the temperature falling and insulation resistances increasing. Typical drying-out curves are shown in FIG. 44.
Where mobile vacuum treatment plant is not available for site drying alternative methods need to be employed. These are the oil-immersed resistor heating and short-circuit methods which, though less appropriate for large high-voltage transformers, can prove satisfactory if no alternative is available.
Oil-immersed resistor heating
This method consists of drying the transformer and oil simultaneously in the transformer tank. Suitable resistor units are lowered into the bottom of the tank in order to raise the oil temperature.
The tank should be filled with oil to the working level and the oil should be allowed to stand for an hour or so. The tank cover should be raised at least 30 mm, or, better still, removed altogether in order to allow perfectly free egress of the moisture vaporized during the drying-out process.
In order to conserve the heat generated in the resistors the sides of the transformer tank should preferably be well lagged using, say, wagon sheets, sackings or any similar coverings which may be available. The resistors should be spaced as symmetrically as possible round the inside of the tank in order to distribute the heat. During the drying-out process the top oil tempera ture should be maintained at a value not exceeding 85ºC. It should be borne in mind that in the immediate vicinity of the resistor units the oil will be at a higher temperature than is indicated at the top of the tank, and consequently the temperature near the resistors is the limiting factor. The temperature may be measured by a thermometer immersed on the top layers of the oil.
During the drying out process the following readings should be taken at frequent regular intervals:
(a) Insulation resistance between HV and LV windings and between each winding and earth.
There are three stages in the complete process. First, the heating up stage, which is of relatively short duration, when the temperature is increasing from the ambient to the recommended maximum for drying out and the insulation resistance of the windings is falling. Second, the longest and real drying period, when the temperature is maintained constant and the insulation resistance becomes approximately constant but starts to rise at a point towards the end of this period. Third, which is again of short duration, when the supply to the resistors is cut off, the temperature falling, and the insulation resistance increasing.
On no account should a transformer be left unattended during any part of the drying-out process.
This method is also used for:
(a) Drying out the transformer and oil simultaneously in the transformer tank.
(b) Drying the transformer only, out of its tank.
Dealing first with (a), the same initial precautions are taken as described earlier.
The LV winding is short circuited, a low single-phase or three-phase voltage being applied to the HV windings, and of a value approaching the full-load impedance voltage of the transformer. If a suitable single-phase voltage only is available, the HV windings should temporarily be connected in series, as shown in FIG. 45. A voltmeter, ammeter and fuses should be connected in circuit on the high-voltage side. If the voltage available is not suitable for supplying the HV winding, but could suitably be applied to the low voltage, this may be done and the HV winding instead short circuited. In this case special care must be taken to avoid breaking the short-circuiting connection as, if this is broken, a high voltage will be induced in the HV winding which will be dangerous to the operator.
The temperature should be measured both by a thermometer in the oil and, if possible, by the resistance of the windings. In the former case it is preferable to use spirit thermometers, but if mercury thermometers only are available, they should be placed outside the influence of leakage magnetic fields, as otherwise eddy currents may be induced in the mercury, and the thermometers will give a reading higher than the true oil temperature. The resistance measurements are taken periodically during the drying-out period. These measurements are made by utilizing any suitable DC supply, and Figs 45 and 46 indicate the connections. If tappings are fitted to either winding the tapping selector or link device should be positioned so that all winding turns are in circuit during the drying-out process. The AC supply for heating the transformer is, of course, temporarily interrupted when taking DC resistance measurements.
The temperature in degrees C corresponding to any measured resistance is given by the following formula:
(Note: 235 becomes 225 for aluminum.)
where T2 is the temperature of the windings when hot
T1 is the temperature of the windings when cold
R2 is the resistance of the windings when hot
R1 is the resistance of the windings when cold
Temperature rise of the windings is T2 - T1
The maximum average temperature of each winding measured by resistance should not be allowed to exceed 95ºC. If it is not possible to take the resistance of the windings, the top oil temperature should not exceed 85ºC.
Dealing next with (b), the transformer being dried out separately and out of its tank, the method is electrically the same as for (a), but the applied volt age must be lower. The transformer should be placed in a shielded position to exclude draughts, and the steady drying-out temperature measured by resistance must not exceed 95ºC.
The value of drying-out currents will, of course, be less than when drying out the transformer in oil, but the attainment of the specified maximum permissible temperature is the true indication of the current required.
If the transformer has been stored on its plinth full of oil, it will also be necessary to erect the cooler and pipework and fill this with oil before it can go into service. Initially, any free-standing separate cooler should be filled with the main tank isolating valves closed and the oil circulated via a tank by-pass pipe to dislodge any small bubbles of air which can be vented via the cooler vent plugs.
Normally, such a tank by-pass would probably be installed by the manufacturer as a temporary fitment provided that he was given the responsibility for site installation, but it is a worthwhile practice to retain them as permanent features on large transformers so that the feature is readily available at any time in the future when work on the transformer necessitates any draining of the oil.
If tank-mounted radiators have been fitted at site so that these must be filled with oil, then they must be vented of all air before the valves connecting these with the main tank are opened.
The oil necessary to bring the level up to minimum operating level can then be added via the conservator filling valve and, once the conservator is brought into operation, the breather should be put into service. If of the desiccant type, this should be checked to ensure it is fully charged with active material and that the oil seal is filled in accordance with the makers' instructions. If a refrigeration breather is supplied as may be the case for transformers of 275 kV and above, this needs an auxiliary power supply which should, if necessary, be supplied from site supplies, so that the breather can be made alive as soon as possible without waiting for the marshalling kiosk to be installed and energized.
Transport to site could well have involved a journey of many hundreds of miles, part possibly by sea. The transformer will have had at least two lots of handling. There is, however, very little testing which can be done at site which can demonstrate that it has not suffered damage. It is therefore vital that such tests as can be carried out at site should be done as thoroughly and as carefully as possible. These may include:
• Ratio measurement on all taps.
• Phasor group check.
• Winding resistance measurements on all taps.
• Operation of tapchanger up and down its range. Check the continuity of tapped winding throughout the operation.
• Insulation resistance between all windings and each winding to earth.
• Insulation resistance core -to earth, core -to frame and core frame -to earth.
• No-load current measurement at reduced voltage; very likely this will be done at 415 V and compared with the current obtained at the same voltage in the works.
• Oil samples taken and checked for breakdown strength and moisture con tent. For a large important transformer for which the oil is to be tested periodically for dissolved-gas content, this sample would also be checked for gas content and taken as the starting point.
• All control, alarms, protection and cooler gear checked for correct operation. Alarm settings and protection trips set to appropriate level for initial energization.
• If FRA measurements were made in the factory (see Section 5.2), these should be repeated at this time and the results compared with those obtained in the factory.
• Tank and cooler earth connections checked as well as the earthing of the HV neutral, if appropriate.
Insulators outside the tank should be cleaned with a dry cloth. The transformer tank and cover should be effectively earthed in a direct and positive manner while, in order to comply with any statutory regulations, the low-voltage neutral point of substation and similar transformers should also be earthed.
In unattended substations it is an advantage to fit each transformer with a maximum indicating thermometer, so that a check can be kept upon the temperature rise.
The setting of alarms is dependent on local ambient and loading conditions, but is usually based on the EN maximum oil temperature rise of 60ºC. Alarm thermometers, which depend upon oil temperature, might be set at 85ºC and 90ºC respectively to take account of the inherent time lag between maximum and top oil temperatures. Winding temperature indicators, which more closely follow variations of winding temperature, are used for all large transformers and might have a warning alarm set at 105ºC and a trip at 110ºC: these values are similarly subject to local ambient and loading conditions. (Selection of set tings for oil and winding temperature alarms and trips is discussed in greater depth in Section 6.8 which deals with effects of sustained abnormal operating conditions.) It must be borne in mind that there will be a temperature gradient between the actual maximum temperature of the copper conductors and that registered in the top of the oil, the former, of course, being the higher. This accounts for the differences suggested between the permissible continuous temperature and the alarm temperatures.
Protection settings may be set to a lower level than the recommended permanent settings for the initial energization.
If the transformer is not required to operate in parallel with other transformers, the voltage may now be applied. It is desirable to leave the transformer on no load for as long a period as possible preceding its actual use, so that it may be warmed by the heat from the iron loss, as this minimizes the possible absorption of moisture and enables any trapped air to be dispelled by the convection currents set up in the heated oil. The same objective would be achieved by switching in directly on load, but for transformers fitted with gas actuated relay protection the supply may be interrupted by the dispelled gas from the oil actuating the relay, which could then trip the supply breaker.
If, however, the transformer has to operate in parallel with another unit, it should be correctly phased in, as described in the section dealing with parallel operation, before switching on the primary voltage. It is essential that the secondary terminal voltages should be identical, otherwise circulating currents will be produced in the transformer windings even at no load. Transformers of which the ratings are greater than three to one should not be operated in parallel.
Switching in or out should be kept to an absolute minimum. In the case of switching in, the transformer is always subject to the application of steep fronted travelling voltage waves and current in-rushes, both of which tend to stress the insulation of the windings, electrically and mechanically, so increasing the possibility of ultimate breakdown and short circuit between turns. From the point of view of voltage concentration it is an advantage, wherever possible, to excite the transformers from the low-voltage side, although, on the other hand, the heaviest current in-rushes are experienced when switching in on the low-voltage side. The procedure adopted will therefore be one of expediency, as determined from a consideration of voltage surges and heavy current in-rushes.
If the protection settings have been put to a lower level for initial energization, these should be returned to their recommended values for permanent service.
Installation of dry-type transformers
Compared with its oil-filled counterpart, installation of a dry-type transformer is a very much simpler operation. Many of the aspects to be considered are, however, similar.
The unit must first be carefully examined to ensure that it has not sustained damage during shipment. This task is made simpler than for an oil-filled unit in that the core and coils themselves are visible. Leads and bus bars, however, do not have the benefit of a steel tank for protection. Off-loading and handling on site represent particularly hazardous activities for these components so it is important to ensure that these are all intact on completion of this operation. The exterior of all windings must be unmarked and windings must be securely located. It is likely that the transformer will be installed inside a sheet-steel enclosure. If so, this must be firmly bolted down and the unit correctly located and secured within the enclosure so that all electrical clearances are correctly obtained.
The following electrical checks should be made before any connections are made to the transformer:
• Insulation resistance, between all windings and each winding to earth.
• Voltage ratio on all taps.
• Phasor group check.
On satisfactory completion of checks to prove the electrical integrity of the transformer the electrical connections may be installed. If this activity is likely to take some time, arrangements should be made to keep the transformer clean, warm and dry in the intervening period. Connections could involve links to the HV terminals from a cable terminating box on the outside of the transformer enclosure, or direct connection of HV cable tails to the HV winding terminals. Low voltage connections will very likely be direct to the bus bars of the incoming circuit breaker of a distribution switchboard. Following completion of the connections, repeat HV and LV insulation resistance measurements to earth should be carried out, bonding of the core and core frame to the switchgear earth should be verified and correct operation of any control and/or protective devices should be proven.
The appropriate tap position should be selected on any off-circuit tapping selector.
Protection trips should be set to the appropriate level for initial energization.
When all electrical checks have been satisfactorily concluded, preparations can be made for closing the HV circuit breaker; all construction materials removed from the transformer cubicle, any temporary earths removed, covers replaced, doors closed to release any mechanical interlock keys for the HV breaker.
There is not the necessity to allow a period of 'soak' following initial energization of a dry-type transformer as in the case of an oil-filled unit since there is no possibility of entrapped air needing to be released, or any other warming-up mechanism best carried out off-load. If the transformer is to operate in parallel with an existing supply it must be phased in across the LV circuit breaker in the same way as described for oil-filled units. When the LV circuit breaker has been closed the protection trips should be set to their specified running settings.