Industrial Power Transformers-- Transformer construction (part 9)

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Cable box connections

Cable boxes are the preferred means of making connections at 11, 6.6, 3.3 kV and 415 V in industrial complexes, as for most other electrical plant installed in these locations. Cabling principles are not within the scope of this volume and practices differ widely, but the following section reviews what might be considered best practice for power transformer terminations on HV systems having high fault levels.

Modern polymeric-insulated cables can be housed in air-insulated boxes.

Such connections can be disconnected with relative simplicity and it is not therefore necessary to provide the separate disconnecting chamber needed for a compound-filled cable box with a paper-insulated cable. LV line currents can occasionally be as high as 3000 A at 11 kV, for example on the station transformers of a large power station and, with cable current ratings limited to 600-800 A, as many as five cables per phase can be necessary. For small transformers of 1 MVA or less on high fault level installations it is still advantageous to use one cable per phase since generally this will restrict faults to single phase to earth. On fuse-protected circuits at this rating three-core cables are a possibility. Since the very rapid price rise of copper which took place in the 1960s, many power cables are made of aluminum. The solid conductors tend to be bulkier and stiffer than their copper counterparts and this has to be taken into account in the cable box design if aluminum cored cables are to be used. Each cable has its own individual gland plate so that the cable jointer can gland the cable, maneuver it into position and connect it to the terminal. Both cable core and bushing will usually have palm-type terminations which are connected with a single bolt. To give the jointer some flexibility and to provide the necessary tolerances, it is desirable that the glandplate-to-bushing terminal separation should be at least 320 mm.

For cable ratings of up to 400 A, non-magnetic gland plates should be used.

For ratings above 400 A, the entire box should be constructed of non-magnetic material in order to reduce stray losses within the shell which would otherwise increase its temperature rise, with the possible risk of overheating the cable insulation. To enable the box to breathe and to avoid the build-up of internal condensation, a small drain hole, say 12 mm in diameter, is provided in one glandplate.

FIG. 104 shows a typical 3.3 kV air-insulated cable box having a rating of about 2400 A with 4 _ 400 mm2 aluminum cables per bushing.

At 11 kV, some stress control is required in an air-insulated box, so the bushing and cable terminations are designed as an integrated assembly, as shown in FIG. 105(a).

FIG. 104 3.3 kV cable box

FIG. 105 11 kV cable box and section of 11 kV elastimold elbow termination

FIG. 105(b) shows a cross-section of a typical molded-rubber socket connector which is fitted to the end of an 11 kV cable. This has internal and external semiconductive screens: the inner screen, the cable conductor connector and the outer provides continuity for the cable outer screen, so that this encloses the entire termination. The external screen is bonded to earth by connection to the external lug shown in the figure. The joint is assembled by fitting the socket connector over the mating bushing and then screwing the insulating plug, containing a metal threaded insert, onto the end of the bushing stem. This is tightened by means of a spanner applied to the hexagonal-nut insert in the outer end of this plug. This insert also serves as a capacitative voltage test point. After making the joint, this is finally covered by the semi conducting molded-rubber cap.

Since the external semi-conductive coating of this type of connector is bonded to earth, there would be no electrical hazard resulting from its use without any external enclosure and, indeed, it is common practice for a connector of this type to be used in this way in many European countries provided that the area has restricted access. However, UK practice is usually to enclose the termination within a non-magnetic sheet steel box to provide mechanical protection and phase isolation. Should a fault occur, this must be contained by the box which ensures that it remains a phase-to-earth fault, normally limited by a resistor at the system neutral point, rather than developing into an unrestricted phase-to-phase fault.

For higher voltage terminations, that is at 132, 275 and 400 kV, direct cable connections are occasionally made to transformers. These usually consist of an oil-filled sealing-end chamber with a link connected to an oil/oil bushing through the transformer tank cover. Cable connections are now generally made via an intermediate section of SF6 trunking as described above.

Tank-mounted coolers

Tank-mounted pressed-steel radiators now represent the most widely used arrangement for cooling smaller transformers for which tank surface alone is not adequate. These can now be manufactured so cheaply and fitted so easily that they have totally replaced the arrangement of tubes which were commonly used for most distribution transformers. They are available in various patterns but all consist basically of a number of flat 'passes' of edge-welded plates connecting a top and bottom header. Oil flows into the top and out of the bottom of the radiators via the headers and is cooled as it flows downwards through the thin sheet-steel passes. The arrangement is most suited to transformers having natural oil and natural air circulations, that is, ONAN cooling, as defined in EN 60076-2.

For larger units it is be possible to suspend a fan below or on the side of the radiators to provide a forced draught, ONAF arrangement. This might enable the transformer rating to be increased by some 25 percent, but only at the extra cost and complexity of control gear and cabling for, say, two or four fans. Achievement of this modest uprating would require that the radiators be grouped in such as way as to obtain optimum coverage by the fans. With small transformers of this class, much of the tank surface is normally taken up with cable boxes, so that very little flexibility remains for location of radiators. For units of around 30 MVA the system becomes a more feasible option, particularly at 132/33 kV where connections are frequently via bushings on the tank cover rather than cable boxes on the sides. One problem with this arrangement is that in order to provide space below the radiators for installation of a fan, the height of the radiator must be reduced, so that the area for self-cooling is reduced. The alternative of hanging the fans from the side of the radiators requires that careful consideration be given to the grouping of these to ensure that the fans blow a significant area of the radiator surface.

It is frequently a problem to accommodate tank-mounted radiators whilst leaving adequate space for access to cable boxes, the pressure relief vent pipe and the like. The cooling-surface area can be increased by increasing the number of passes on the radiators, but there is a limit to the extent to which this can be done, dictated by the weight which can be hung from the top and bottom headers. If fans are to be hung from the radiators this further increases the cantilever load. It is possible to make the radiators slightly higher than the tank so that the top header has a swan-necked shape: this has the added benefit that it also improves the oil circulation by increasing the thermal head developed in the radiator. However, this arrangement also increases the overhung weight and has the disadvantage that a swan-necked header is not as rigid as a straight header, so that the weight-bearing limit is probably reached sooner. The permissible overhang on the radiators can be increased by providing a small stool at the outboard end, so that a proportion of the weight bears directly onto the transformer plinth; however, since this support is not available during transport, one of the major benefits from tank-mounted radiators, namely, the ability to transport the transformer full of oil and fully assembled is lost. The FIG. 106 shows two views of a small 33/11 kV unit with tank-mounted radiators having side-mounted fans. By clever design it has been possible to include an oil pump in the cooling circuit to provide forced circulation and, because the unit has been designed for low losses, only two radiators are necessary, leaving plenty of room for cable boxes. Note, however, that these are significantly higher than the transformer tank. The transformer has an ONAN rating of 4 MVA which can be increased to 8 MVA with the pump and fans in operation.

On all but the smallest transformers each radiator should be provided with isolating valves in the top and bottom headers as well as drain and venting plugs, so that it can be isolated, drained and removed should it leak. The valves may be of the cam-operated butterfly pattern and, if the radiator is not replaced immediately, should be backed up by fitting of blanking plates with gaskets.

Radiator leakage can arise from corrosion of the thin sheet steel, and measures should be taken to protect against this. Because of their construction it is very difficult to prepare the surface adequately and to apply paint protection to radiators under site conditions, so that if the original paint finish has been allowed to deteriorate, either due to weather conditions or from damage in transit, it can become a major problem to make this good. This is particularly so at coastal sites. Many users specify that sheet-steel radiators must be hot dip galvanized in the manufacturer's works prior to receiving an etch-prime, followed by the usual paint treatment in the works.

FIG. 106 Two views of a 4/8 MVA, three-phase, 33/11 kV, 50 Hz transformer with tank-mounted radiators

FIG. 107 Single-phase 765/242 kV, 300 MVA autotransformer showing tank-mounted radiators in groups on sub-headers with oil pumps and fans (Areva T&D)

Separate cooler banks

As already indicated, one of the problems with tank-mounted radiators is that a stage is reached when it becomes difficult to accommodate all the required radiators on the tank surface, particularly if a significant proportion of this is taken up with cable boxes. In addition, with the radiators mounted on the tank, the only straightforward option for forced cooling is the use of forced or induced draught fans, and, as was explained in Section 4.5, the greater benefits in terms of increasing rating are gained by forcing and directing the oil flow. It is possible to mount radiators, usually in groups of three, around the tank on sub-headers with an oil circulating pump supplying the sub-headers as shown in FIG. 107. This is an arrangement used by many utilities worldwide. It has the advantage that the unit can be dispatched from the works virtually complete and ready for service. The major disadvantage is the larger number of fans and their associated control gear which must be provided compared with an arrangement using a separate free-standing cooler bank. It is therefore worthwhile considering the merits and disadvantages of mounting all cooler equipment on the tank compared with a separate free-standing cooler arrangement favored by many utilities.

Advantages of all tank-mounted equipment

• More compact arrangement saves space on site.

• The transformer can be transported ready filled and assembled as a single entity, which considerably reduces site-erection work.

• The saving of pipework and headers and frame/support structure reduces the first cost of the transformer.


• Forced cooling must usually be restricted to fans only, due to the complication involved in providing a pumped oil system. If oil pumps are used a large number are required with a lot of control gear.

• Access to the transformer tank and to the radiators themselves for maintenance/painting is extremely difficult.

• A noise-attenuating enclosure cannot be fitted close to the tank.

If these advantages are examined more closely, it becomes apparent that these may be less real than at first sight. Although the transformer itself might well be more compact, if it is to achieve any significant increase in rating from forced cooling, a large number of fans will be required, and a considerable unrestricted space must be left around the unit to ensure a free airflow without the danger of recirculation. In addition, since the use of forced and directed oil allows a very much more efficient forced cooled design to be produced, the apparent saving in pipework and cooler structure can be easily offset. Looking at the disadvantages, the inability to fit a noise-attenuating enclosure can be a serious problem for larger transformers as environmental considerations acquire increasingly more prominence.

The protagonists of tank-mounted radiators tend to use bushings mounted on the tank cover for both HV and LV connections, thus leaving the tank side almost entirely free for radiators.

Having stated the arguments in favor of free-standing cooler banks, it is appropriate to consider the merits and disadvantages of forced cooling as against natural cooling.

The adoption of ODAF cooling for say, a 60 MVA bulk supplies transformer, incurs the operating cost of pumps and fans, as well as their additional

first cost and that of the necessary control gear and cabling. Also, the inherent reliability is lower with a transformer which relies on electrically driven auxiliary equipment compared with an ONAN transformer which has none.

On the credit side, there is a considerable reduction in the plan area of the cooler bank, resulting in significant space saving for the overall layout. A typical ONAN/ODAF-cooled bulk supplies transformer is rated to deliver full out put for conditions of peak system loading and then only when the substation of which it forms part is close to its maximum design load, that is near to requiring reinforcement, so for most of its life the loading will be no more than its 30 MVA ONAN rating. Under these circumstances, it is reasonable to accept the theoretical reduction in reliability and the occasional cooler equipment losses as a fair price for the saving in space. On the other hand, a 50 MVA unit transformer at a power station normally operates at or near to full out put whenever its associated generator is on load, so reliance on other ancillary equipment is less desirable and, if at all possible, it is preferable to find space in the power station layout to enable it to be totally naturally cooled.

Where a transformer is provided with a separate free-standing cooler bank, it is possible to raise the level of the radiators to a height which will create an adequate thermal head to ensure optimum natural circulation. The longest available radiators can be used to minimize the plan area of the bank consistent with maintaining a sufficient area to allow the required number of fans to be fitted. It is usual to specify that full forced-cooled output can be obtained with one fan out of action. Similarly, pump failure should be catered for by the provision of two pumps, each capable of delivering full flow. If these are installed in parallel branches of cooler pipework, then it is necessary to ensure that the non-running pump branch cannot provide a return path for the oil, thus allowing this to bypass the transformer tank. Normally this would be achieved by incorporating a non-return valve in each branch. However, such a valve could create too much head loss to allow the natural circulation necessary to provide an ONAN rating. One solution is to use a flap valve of the type shown in FIG. 108, which provides the same function when a pump is running but will take up a central position with minimal head loss for thermally induced natural circulation.

FIG. 108 Oil flap value Water cooling

Water cooling of the oil is an option which is available for large transformers and in the past was a common choice of cooling for many power station transformers, including practically all generator transformers and many station and unit transformers. It is also convenient in the case of large furnace transformers, for example, where, of necessity, the transformers must be close to the load - the furnace - but in this location ambients are not generally conducive to efficient air cooling. The choice of oil/water was equally logical for power station transformers since there is usually an ample source of cooling water available in the vicinity and oil/water heat exchangers are compact and thermally efficient. The arrangement does not provide for a self-cooled rating, since the head loss in oil/water heat exchangers precludes natural oil circulation, but a self-cooled rating is only an option in the case of the station transformer any way. Generally when the unit is on load both generator and unit transformers are near to fully loaded.

The risk of water entering the transformer tank due to a cooler leak has long been recognized as the principle hazard associated with water cooling. This is normally avoided by ensuring that the oil pressure is at all times greater than that of the water, so that leakage will always be in the direction of oil into water. It is difficult to ensure that this pressure difference is maintained under all possible conditions of operation and malfunction. Under normal conditions, the height of the transformer conservator tank can be arranged such that the minimum oil-head will always be above that of the water. However, it is difficult to make allowance for operational errors, for example, the wrong valve being closed, so that maximum pump discharge pressure is applied to an oil/water interface, or for equipment faults, such as a pressure-reducing valve which sticks open at full pressure.

The precise cost of cooling water depends on the source, but at power stations it is often pumped from river or sea and when the cost of this is taken into consideration, the economics of water cooling become far less certain. In the early 1970s, after a major generator transformer failure attributable to water entering the oil through cooler leaks, the UK Central Electricity Generating Board reassessed the merits of use of water cooling. The high cost of the failure, both in terms of increased generating costs due to the need to operate lower-merit plant and the repair costs, as well as pumping costs, resulted in a decision to adopt an induced draught air-cooled arrangement for the Littlebrook D generator transformers and this subsequently became the standard, whenever practicable.

FIG. 109 Diagrammatic arrangement of Dinorwig generator transformer cooler circuits

In water-cooling installations, it is common practice to use devices such as pressure-reducing valves or orifice plates to reduce the waterside pressures.

However, no matter how reliable a pressure-reducing valve might be, the time will come when it will fail, and an orifice plate will only produce a pressure reduction with water flowing through it, so that should a fault occur which pre vents the flow, full pressure will be applied to the system.

There are still occasions when it would be very inconvenient to avoid water cooling, for example in the case of furnace transformers mentioned above.

Another example is the former CEGB's Dinorwig pumped-storage power station, where the generator transformers are located underground, making air cooling impracticable on grounds of space and noise as well as the undesirability of releasing large quantities of heat to the cavern environment. FIG. 109 shows a diagrammatic arrangement of the cooling adopted for the Dinorwig generator transformers. This uses a two-stage arrangement having oil/towns water heat exchangers as the first stage, with second-stage water/water heat exchangers having high-pressure lake-water cooling the intermediate towns water. The use of the intermediate stage with recirculating towns water enables the pressure of this water to be closely controlled and, being towns water, waterside corrosion/erosion of the oil/water heat exchangers - the most likely cause of cooler leaks - is also kept very much under control. Pressure control is ensured by the use of a header tank maintained at atmospheric pressure. The level in this tank is topped up via the ball valve and a very generously sized overflow is provided so that, if this valve should stick open, the header tank will not become pressurized. The position of the water pump in the circuit and the direction of flow is such that should the water outlet valve of the oil/water heat exchanger be inadvertently closed, this too would not cause pressurization of the heat exchanger. A float switch in the header tank connected to provide a high-level alarm warns of either failure of the ball valve or leakage of the raw lake water into the intermediate towns water circuit.

Other situations in which water cooling is justified such as those in which the ambient air temperature is high, so that a significantly greater temperature rise of the transformer can be permitted if water cooling is employed, might use an arrangement similar to that for Dinorwig described above, or alternatively, a double-tube/double-tubeplate cooler might be employed. With such an arrangement, shown diagrammatically in FIG. 110, oil and water circuits are separated by an interspace so that any fluid leakage will be collected in this space and will raise an alarm. Coolers of this type are, of course, significantly more expensive than simple single-tube and plate types and heat transfer is not quite so efficient, so it is necessary to consider the economics carefully before adopting a double tube/double-tubeplate cooler in preference to an air-cooled arrangement.

Another possible option which might be considered in a situation where water cooling appears preferable is the use of sophisticated materials, for example, titanium-tubed coolers. This is usually less economic than a double tubed/double-tubeplate cooler as described above.

Passing mention has been made of the need to avoid both corrosion and erosion of the water side of cooler tubes. A third problem which can arise is the formation of deposits on the water side of cooler tubes which impair heat transfer. The avoidance of all of these requires careful attention to the design of the cooling system and to carefully controlled operation. Corrosion problems can be minimized by correct selection of tube and tubeplate materials to suit the analysis of the cooling water. Deposition is avoided by ensuring that an adequate rate of water flow is maintained, but allowing this to become excessive will lead to tube erosion.

If the cooling medium is sea water, corrosion problems can be aggravated and these might require the use of measures, such as the installation of sacrificial anodes or cathodic protection. These measures have been used with success in UK power stations, but it is important to recognize that they impose a very much greater burden on maintenance staff than does an air cooler, and the consequences of a small amount of neglect can be disastrous.

FIG. 110 Double tube, double tubeplate oil/water heat exchanger

A fan and its control equipment can operate continuously or under automatic control for periods of 3-5 years or more, and maintenance usually means no more than greasing bearings and inspection of contactor contacts. By contrast, to ensure maximum freedom from leaks, most operators of oil/water heat exchangers in UK power stations routinely strip them down annually to inspect tubes, tubeplates and water boxes. Each tube is then non-destructively tested for wall thickness and freedom from defects, using an eddy current probe. Suspect tubes can be blanked off but, since it will only be permissible to blank-off a small proportion of these without impairing cooling, a stage can be reached when complete replacement tubenests are necessary.

In view of the significant maintenance requirement on oil/water heat exchangers, it is advisable to provide a spare cooler and standard practice has, therefore, been to install three 50 percent rated coolers, one of which will be kept in a wet standby condition, that is, with the oil side full of transformer oil and with the water side inlet and outlet valves closed but full of clean water, and the other two in service.

FIG. 111 Oil circuit for ONAN/ODAF-cooled unit transformer

Cooler control

Ancillary plant to control and operate forced cooling plant must be provided with auxiliary power supplies and the means of control. At its most basic, this takes the form of manual switching at a local marshalling panel, housing auxiliary power supplies, fuses, overloads protection relays and contactors. In many utilities due to high labor costs the philosophy has been to reduce the amount of at-plant operator control and so it is usual to provide remote and/or automatic operation.

The simplest form of automatic control uses the contacts of a winding temperature indicator to initiate the starting and stopping of pumps and fans. Further sophistication can be introduced to limit the extent of forced cooling lost should a pump or fan fail. One approach is to subdivide the cooler bank into two halves, using two 50 percent rated pumps and two sets of fans. Equipment failure would thus normally not result in loss of more than half of the forced cooling.

As has been explained above, many forced-cooled transformers have a rating which is adequate for normal system operation when totally self-cooled, so an arrangement which requires slightly less pipework having parallel 100 percent rated duty and standby pumps, as shown in FIG. 111, can be advantageous.

This means that flow switches must be provided to sense the failure of a duty pump and to initiate start-up of the standby should the winding temperature sense that forced cooling is required.

A large generator transformer has virtually no self-cooled rating, so pumps can be initiated from a voltage-sensing relay, fed from a voltage transformer which is energized whenever the transformer is energized. Two 100 percent duty and standby oil pumps are provided, with automatic initiation of the standby pump should flow-failure be detected on the duty pump. Fans may still be controlled from a winding temperature indicator, but it is usual to divide these into two groups initiated in stages, the first group being switched on at a winding temperature of 80ºC and out at 70ºC. The second group is switched on at 95ºC and out at 80ºC. The total number of fans provided is such that failure of any one fan still enables full rating to be achieved with an ambient temperature of 30ºC. The control scheme also allows each oil pump to serve either in the duty or standby mode and the fans to be selected for either first- or second-stage temperature operation. A multiposition mode selector switch allows both pumps and fans to be selected for 'test' to check the operation of the control circuitry. The scheme is also provided with 'indication' and 'alarm' relay contacts connected to the station data processor.

For water-cooled generator transformers, the fans are replaced by water pumps which are controlled from voltage transformer signals in the same way as the oil pumps. Two 100 percent duty and standby pumps are provided, with the standby initiated from a flow switch detecting loss of flow from the selected duty pump.

There is a view that automatic control of generator transformer air coolers is unnecessary and that these should run continuously whenever the generator transformer is energized. This would simplify control arrangements and reduce equipment costs but there is an operational cost for auxiliary power. Modern fans have a high reliability, so they can be run for long periods continuously without attention. For many large generator transformers, running of fans (whether required or not) results in a reduction of transformer load loss, due to the reduced winding temperature, which more than offsets the additional fan power requirement, so that this method of operation actually reduces operating cost. In addition, the lower winding temperature reduces the rate of usage of the transformer insulation life. An example will assist in making this clear.

An 800 MVA generator transformer might typically operate at a throughput of 660 MW and 200 MVAr, which is equivalent to 690 MVA. At 800 MVA, it will have resistance rise and top-oil rise of 70ºC and 60ºC, respectively, if the manufacturer has designed these to the BS limits. At 690 MVA, these could be reduced to 45ºC and 41ºC, respectively, dependent on the particular design.

Then, as explained in Section 4.5, the winding hot spot temperature at an ambient temperature of, say, 10ºC will be given by:

Ambient 10

Rise by resistance 45

Half (outlet - inlet) oil 6

Maximum gradient - average gradient 4

Total 65ºC

At this ambient, the first fan group will operate under automatic control, trip ping in when the hot spot temperature reaches 80ºC and out at 70ºC. It is reasonable to assume, therefore, that with these fans running intermittently, an average temperature of 75ºC will be maintained. Hence, continuous running of all fans will achieve a temperature reduction of about 10ºC.

For an actual case estimating the extra auxiliary power absorbed by running the fans continuously would probably involve making observations of operation in the automatic control mode first. However, by way of illustration, it is convenient to make some very approximate estimates.

The power absorbed by 12 fans on a transformer of this rating might typically be 36 kW. If, at this ambient, the first group would run for about 80 percent of the time and the second group would not run at all, the average auxiliary power absorbed would be 0.8 times 18 kW, equals 14.4 kW, say 15 kW. Running them all continuously therefore absorbs an extra (36 - 15) kW, equals 21 kW.

The load loss of an 800 MVA generator transformer at rated power could be 1600 kW. At 690 MVA this would be reduced to about 1190 kW. If it is assumed that 85 percent of this figure represents resistive loss, then this equates to 1012 kW, approximately. A 10ºC reduction in the average winding temperature would produce a reduction of resistance at 75ºC of about 3.3 percent, hence about 33.4 kW of load loss would be saved. Strictly speaking, this reduction in resistance would cause an approximately 3.3 percent increase in the other 15 percent of the load losses, that is about 6 kW additional stray losses would be incurred, so that the total power saved would be 33.4 kW at a cost of (21 _ 6) equals 27 kW, that is 6.4 kW nett saving. However, the figures used are only very approximate but they demonstrate that the cost of the increased auxiliary power is largely offset by load loss savings. The important feature, though, is that the lower hot spot temperature increases insulation life.

For example, referring to Section 4.5, the 10ºC reduction obtained in the above example would, theoretically, increase the life of the insulation somewhere between three and fourfold.

FIG. 112 Transformers temperature controller (Accurate Controls Ltd)

Winding temperature indicators

In the foregoing paragraphs mention was made of control of cooling equipment from a winding temperature indicator. Before leaving this Section dealing with ancillary equipment it is perhaps appropriate to say a little more about winding temperature indicators, or more precisely, transformer temperature controllers.

One such device is shown in FIG. 112. This consists of a liquid filled bulb at the end of a steel capillary. The bulb is placed in the hottest oil in the top of the transformer tank and the capillary is taken to the transformer marshal ling cubicle where it terminates in a steel bellows unit within the temperature controller. The controller contains a second bellows unit connected to another capillary which follows the same route as that from the transformer tank but this has no bulb at its remote end and it acts as a means of compensation for variations in ambient temperature, since with changes in ambient the liquid in both capillaries expands or contracts with respect to the capillaries and both bellows therefore move together. For changes in oil temperature only the bellows connected to the bulb will move. Movement of both sets of bellows has no effect on the mechanism of the instrument whilst movement only of the bellows connected to the bulb, causes the rotation of a temperature indicating pointer and a rotating disc which carries up to four mercury switches.

The pointer can be set to give a local visual indication of oil temperature and the mercury switches can be individually set to change over at predetermined temperature settings. The mercury switches can thus provide oil temperature alarm and trip signals and also a means of sending a start signal to pumps and/or fans. The pointer is also connected to a potentiometer which can be used to provide remote indication of temperature. If it is required to have an indication of winding temperature the sensing bulb can be located in the hot test oil but surrounded by a heater coil supplied from a current transformer in either HV or LV winding leads. The heater coil is then designed to produce a temperature-rise above hottest oil equivalent to the temperature-rise of the HV or LV hot spot above the hottest oil. This is known as a thermal image device.

The heater coil is provided with an adjustable shunt so that the precise thermal image can be set by shunting a portion of the CT output current. Of course, the setting of this heater coil current requires that the designer is able to make an accurate estimate of the hot spot rise, and, as indicated in Section 4.5, this might not always be the case. If the transformer is subjected to a temperature rise test in the works, it is usual practice to carry out a final setting of the winding temperature indicators after the individual winding temperature rises have been calculated. On larger transformers one each will be provided for HV and LV windings.

Alternative winding temperature indication

Winding temperature indicators of the type described above are in widespread use in many parts of the world and will no doubt continue to be used for many years to come. The main disadvantage of the 'traditional' winding temperature indicator is that it relies on mercury switches to provide the output signal to control, alarm of tripping circuitry. Mercury is now regarded as environmentally unacceptable and there are pressures to eliminate its use. A simple option for the device described above is to replace the mercury switches with micros witches. The problem with this approach is one of switching current. Operating into a DC circuit at possibly 250 volts, a microswitch can handle no more than a few milliamps compared with the capability of a mercury switch that is measured in amps, so that additional relays are required to provide the necessary output function. Additional complexity and reduced reliability result.

Electronic equipment is likely to be unreliable when operating in the vicinity of the high magnetic fluxes and electric fields associated with power transformers, so that fiber-optic based devices become the only viable alter native. These have the disadvantage that reliability is considered to be poor because of susceptibility to damage during manufacture of the transformer. It was generally considered to be necessary to install several more sensors than ultimately required, in order to ensure that a sufficient number remained serviceable when the transformer was commissioned. Recently, however, a system has been developed whereby at the time of manufacture only the sensor is installed in the transformer windings with a short length of fiber-optic cable. Connection for taking back to the monitoring equipment can then be made to this when the transformer is ready for installation into the tank.

Although this type of winding temperature measurement is unlikely to become the norm for small- and medium-sized transformers, such fiber-optic based solutions are finding much wider use in large high-voltage transformers than a few years ago.


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