Industrial Power Transformers-- Transformer construction (part 8)

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8. TANKS AND ANCILLARY EQUIPMENT

Transformer tanks

The transformer tank provides the containment for the core and windings and for the dielectric fluid. It must withstand the forces imposed on it during transport. On larger transformers, it usually also provides additional structural support for the core during transport. All but the smallest transformers are impregnated with oil under vacuum: the tank acts as the vacuum vessel for this operation.

Transformer tanks are almost invariably constructed of welded boiler plate although in the case of some large transformers manufactured in the UK in the 1960s, aluminum was used in order to enable these to remain within the road transport weight limitations. The tank must have a removable cover so that access can be obtained for the installation and future removal, if necessary, of core and windings. The cover is fastened by a flange around the tank, usually bolted but on occasions welded - more on this aspect later--usually at a high level so that it can be removed for inspection of core and windings, if required, without draining all the oil. The cover is normally the simplest of fabrications, often no more than a stiffened flat plate. It should be inclined to the horizontal at about 1º, so that it will not collect rainwater: any stiffeners should also be arranged so that they will not collect water, either by the provision of drain holes or by forming them from channel sections with the open face downwards.

Even when they are to be finally sealed by means of continuous welding (see below) the joints between the main cover and the tank, and all smaller access covers, are made oil tight by means of gaskets. These are normally of synthetic-rubber bonded cork, or neoprene bonded cork. This material consists of small cork chippings formed into sheets by means of a synthetic-rubber compound. The thickness of the gaskets varies from around 6-15 mm according to the cross-section of the joint, however the important feature is that the material is synthetic-rubber based rather than using natural rubber since the former material has a far greater resistance to degradation by contact with mineral oil.

The tank is provided with an adequate number of smaller removable covers, allowing access to bushing connections, winding temperature CTs, core earthing links, off-circuit tapping links and the rear of tapping selector switches. Since the manufacturer needs to have access to these items in the works the designer ensures that adequate provision is made. All gasketed joints on the tank represent a potential source of oil leakage, so these inspection covers should be kept to a minimum. The main tank cover flange usually represents the greatest oil leakage threat, since, being of large cross section, it tends to provide a path for leakage flux, with the resultant eddy cur rent heating leading to overheating and degradation of gaskets. Removable covers should be large enough to provide adequate safe access, able to with stand vacuum and pressure conditions and should also be small and light enough to enable them to be handled safely by maintenance personnel on site.

This latter requirement usually means that they should not exceed 25 kg in weight.

Occasionally, the tanks of larger transformers may be provided with deep top main covers, so that the headroom necessary to lift the core and windings from the tank is reduced. This arrangement should be avoided, if possible, since a greater quantity of oil needs to be removed should it be necessary to lift the cover and it requires a more complex cover fabrication. It is also possible to provide a flange at low level, which may be additional to or instead of a high-level flange. This enables the cover to be removed on site, thus giving access to core and windings, without the need to lift these heavier items out of the tank. A tank having this arrangement of low-level flange is shown in FIG. 93. It should be noted that whilst it can in certain circumstances be worth while incorporating such features into the design, it is never a straightforward matter to work on large high-voltage transformers on site so that this should not be considered as normal practice. (Nevertheless, in the UK, the CEGB did on a number of occasions carry out successful site repairs which necessitated de-tanking of core and windings. Such on-site working does require careful planning and skilled operators and on these occasions was only undertaken when a clear knowledge of the scope of the work required and the ability to carry this out was evident. Often it is the ability to satisfactorily test on site the efficacy of the work after completion, which can be a critical factor in making the decision to do the work on site.)


FIG. 93 Transformer tank with low-level flange

Tanks which are required to withstand vacuum must be subjected to a type test to prove the design capability. This usually involves subjecting the first tank of any new design, when empty of oil, to a specified vacuum and measuring the permanent deformation remaining after the vacuum has been released.

The degree of vacuum applied usually depends on the voltage class which will determine the vacuum necessary when the tank is used as an impregnation vessel. Up to and including 132 kV transformer tanks a vacuum equivalent to 330 mbar absolute pressure is usually specified and for higher-voltage transformers the vacuum should be 25 mbar absolute. The acceptable permanent deflection after release of the vacuum depends on the dimensions of the tank. Table 4.4 gives an indication of the levels of deflection which may be considered acceptable for particular sizes of tanks.

Table 4 Maximum permissible permanent deflection of tanks and other assemblies following vacuum withstand test: Minimum dimension of tank or fabricated assembly (m) ; Maximum permanent deflection after release of vacuum (mm)

Mention has been made of the need to avoid, or reduce, the likelihood of oil leaks. The welding of transformer tanks does not demand any sophisticated processes but it is nevertheless important to ensure that those welds associated with the tank lifting lugs are of good quality. These are usually crack tested, either ultrasonically or with dye penetrant. Tanks must also be given an adequate test for oil tightness during manufacture. Good practice is to fill with white spirit or some other fairly penetrating low-viscosity liquid and apply a pressure of about 700 mbar, or the normal pressure plus 350 mbar, whichever is the greater, for 24 hours. This must be contained without any leakage.

The tank must carry the means of making the electrical connections. Cable boxes are usual for all voltages up to and including 11 kV, although for pole mounted distribution transformers the preferred arrangement is to terminate the connecting cable in an air sealing end and jumper across to 11 or 3.3 kV bushings on the transformer. Such an arrangement is shown in FIG. 94. Above this voltage air bushings are normally used, although increasing use is now being made of SF6-filled connections between transformer and switchgear at 132 kV and above. This can be particularly convenient in polluted locations or on sites where space is not available for the necessary air clearances required by bushings.

Tanks must be provided with valves for filling and draining, and to allow oil sampling when required. These also enable the oil to be circulated through external filtration and drying equipment prior to initial energization on site, or during service when oil has been replaced after obtaining access to the core and windings. Lifting lugs or, on small units, lifting eyes must be pro vided, as well as jacking pads and haulage holes to enable the transformer to be maneuvered on site. On all but the smaller distribution transformers an oil sampling valve must also be provided to enable a sample of the oil to be taken for analysis with the minimum of disturbance or turbulence, which might cause changes to the dissolved gas content of the sample and thereby lead to erroneous diagnosis. Periodic sampling and analysis of the oil is the most reliable guide to the condition of the transformer in service and an important part of the maintenance routine. This subject is dealt with in Section 6.7. The sampling valve is normally located about 1 m above the tank base in order to obtain as representative a sample as possible.


FIG. 94 11 kV pole-mounted transformer supplied via 11 kV cable having air sealing ends connected via jumpers to bushings on the transformer. Note that the 415 V output from the transformer is also taken away via a cable

Transformer tanks must also have one or more devices to allow the relief of any sudden internal pressure rise, such as that resulting from an internal fault.

Until a few years ago, this device was usually a bursting diaphragm set in an upstand pipe mounted on the cover and arranged to discharge clear of the tank itself. This had the disadvantage that, once it had burst, it allowed an indefinite amount of oil to be released, which might aggravate any fire associated with the fault, and also it left the windings open to the atmosphere. The bursting diaphragm has been superseded by a spring-operated self-resealing device which only releases the volume of oil necessary to relieve the excess pressure before resealing the tank. As shown in FIG. 95, it is essentially a spring loaded valve providing instantaneous amplification of the actuation force.


FIG. 95 Qualitrol pressure relief device

The unit is mounted on a transformer by lugs on the flange and sealed by a mounting gasket. A spring-loaded valve disc is sealed against inner and outer gasket rings by the springs. The valve operates when the oil pressure acting on the area inside the inner gasket ring exceeds the opening force established by the springs. As the disc moves upwards slightly from the inner gasket ring, the oil pressure quickly becomes exposed to the disc area over the diameter of the outer gasket ring, resulting in a greatly increased force, and causing immediate full opening of the valve corresponding to the closed height of the springs.

The transformer pressure is rapidly reduced to normal and the springs then return the valve disc to the closed position. A minute bleed port to the out side atmosphere from the volume entrapped between the gasket rings prevents inadvertent valve opening if foreign particles on the inner gasket ring prevent a perfect ring-to-disc seal. A mechanical indicator pin in the cover, although not fastened to the valve disc, moves with it during operation and is held in the operated position by an O-ring in the pin bushing. This remains clearly visible, indicating that the valve has operated.

No pressure relief device can provide complete protection against all internal pressure transients. On larger tanks, two such devices at opposite ends of the tank improve the protection. It is usual to place the pressure relief device as high on the tank as possible. This minimizes the static head applied to the spring, thus reducing the likelihood of spurious operation in the event of a 'normal' pressure transient, for example, the starting of an oil pump.

However, with the pressure relief device located at high level, there is the risk that operation might drench an operator with hot oil; to prevent this, an enclosure is provided around the device to contain and direct the oil safely down to plinth level. Such enclosure must not, of course, create any significant back pressure which would prevent the relief device from performing its function properly: a minimum cross-section for any ducting of about 300 cm^2 is usually adequate.

To complete the list of fittings on the transformer tank, it is usual to pro vide a pocket, or pockets, in the cover to take a thermometer for measurement of top oil temperature, a diagram/nameplate to provide information of transformer details and an earthing terminal for the main tank earth connection.

Oil preservation equipment --- conservators

Although it is now common for many of the smaller distribution transformers to dispense with a conservator all of the larger more important oil-filled transformers benefit greatly by the use of a conservator.

The use of a conservator allows the main tank to be filled to the cover, thus permitting cover-mounted bushings, where required, and it also makes possible the use of a Buchholz relay (see below). However the most important feature of a conservator is that it reduces the surface area of the oil exposed to atmospheric air. This reduces the rate of oxidization of the oil and also reduces the level of dissolved oxygen, which would otherwise tend to shorten insulation life. The full significance of this aspect of conservators will be made clear in Section 6.7 (see also Section 3.5).

Recent investigation has highlighted the part played by dissolved oxygen in accelerating insulation ageing. Although, to date, there are no published reports of specific measures which have been implemented to reduce levels of dissolved oxygen beyond the use of conservators, it is possible that some arrangement might be introduced to reduce further the degree of contact between oil and air; for example, this could be simply achieved by the use of a parallel-sided conservator having a 'float' covering the surface of the oil. (Some transformer operators in areas with high ambient temperatures and high humidity do, of course, incorporate measures mainly aimed at reducing moisture ingress into the oil. This is discussed further below and in Section 7.)

It is necessary to exclude moisture from the air space above the conservator oil level, in order to maintain the dryness of the transformer oil. For transformers below 132 kV, this space is vented through a device containing a drying agent (usually silica gel) through which the air entering the conservator is passed. When the moisture content of the silica gel becomes excessive, as indicated by the change in colour of an indicator with which it is impregnated, its ability to extract further moisture is reduced and it must be replaced by a further charge of dry material. The saturated gel can be reactivated by drying it in an oven when the colour of the crystals will revert to their original color.

For many years the indicator used was cobalt chloride which was blue when dry changing to pink. This has recently been outlawed because of its toxicity so that nowadays a proprietary organic impregnant is generally used which is bright orange when dry changing to translucent when wet.

The effectiveness of this type of breather depends upon a number of factors: the dryness of the gel, the moisture content of the incoming air and the ambient temperature being the most significant.



FIG. 96 Refrigeration breather


FIG. 97 Conventionally designed conservator tank but with air space filled with synthetic rubber bag to prevent contact between oil and external air

If optimum performance is to be obtained from a transformer having an HV winding of 132 kV and above or, indeed, any generator transformer operating at high load factor, then it is desirable to maintain a high degree of dryness of the oil, typically less than 10 parts per million by volume at 20ºC. Although oil treatment on initial filling can achieve these levels, moisture levels tend to increase over and above any moisture which is taken in through breathing, since water is a product of normal insulation degradation, and this is taking place all the time that the transformer is on load. It is desirable, therefore, to maintain something akin to a continuous treatment to extract moisture from the oil. This is the principle employed in the refrigeration type of breather, illustrated in FIG. 96. Incoming air is passed through a low-temperature chamber which causes any water vapor present to be collected on the chamber walls. The chamber is cooled by means of thermoelectric modules in which a temperature difference is generated by the passage of an electric current (the Peltier effect). Periodically the current is reversed; the accumulated ice melts and drains away. In addition to the drying of the incoming air, this type of breather can be arranged such that the thermosiphon action created between the air in the cooled duct and that in the air space of the conservator creates a continuous circulation and, therefore, a continuous drying action. As the air space in the conservator becomes increasingly dried, the equilibrium level of moisture in the oil for the pressure and temperature conditions prevailing will be reduced so that the oil will give up water to the air in the space above the oil to restore the equilibrium and this, in turn, causes further moisture to migrate from the insulation to the oil, so that a continuous drying process takes place.

The conservator is provided with a sump by arranging that the pipe connecting with the transformer projects into the bottom by about 75 mm. This collects any sludge which might be formed over a period of years by oxidation of the oil. A lockable drain valve is normally fitted and one end of the conservator is usually made removable so that, if necessary, the internals may be cleaned out. One end face usually incorporates a prismatic oil level gauge or a magnetic dial type gauge: these should be angled downwards by some 10-15º, so that they can be easily viewed from plinth level. It is usual to show the minimum, cold oil, 75ºC and maximum oil levels on whichever type of gauge is provided.

Alternative oil preservation systems

Refrigeration breathers are usually considered too costly to be used on any but the larger more expensive transformers operating at 132 kV or higher for which a high level of oil dryness is necessary. In very humid climates such as those prevailing in many tropical countries the task of maintaining a satisfactory level of dryness of the drying agent in a silica-gel-type breather can be too demanding so that alternative forms of breathing arrangements must be adopted. The most common is the air-bag system shown diagrammatically in FIG. 97. With this arrangement the transformer has what is basically a normal conservator except that the space above the oil is filled with a synthetic rubber bag. The interior of the bag is then connected to atmosphere so that it can breathe in air when the transformer cools and the oil volume is reduced and breathe this out when the transformer heats up. With this arrangement the oil is prevented from coming into direct contact with the air, and thereby lies its disadvantage. Water is one of the products of the degradation of paper insulation and as explained in Section 3 the presence of moisture also accelerates the degradation process. If the air space within the conservator is maintained in a dry condition, either by means of a well maintained silica-gel breather or by a refrigeration breather, this will allow moisture to migrate from the oil, and ultimately from the paper insulation to maintain this in a dry condition and minimize ageing. If this moisture remains trapped in the transformer by the presence of a synthetic rubber diaphragm or by other means, the rate of ageing will be increased.

A better arrangement than that just described is again to use basically a normal conservator but to arrange that the space above the oil is filled with dry nitrogen. This can be provided from a cylinder of compressed gas via a pres sure-reducing valve. When the transformer breathes in due to a reduction in load or ambient temperature the pressure-reducing valve allows more nitrogen to be released. When the oil volume increases nitrogen is vented to atmosphere by means of a vent valve. Because the nitrogen is always maintained in a dry state, this arrangement has the great advantage that it maintains the oil and insulation in as dry a condition as possible. The only disadvantage is the supply and cost of the nitrogen needed to maintain a constant supply thus adding to the routine maintenance activities.

It is now common practice, not only in climates having high humidity, for smaller oil-filled distribution transformers to be permanently hermetically sealed.

This has the great advantage of being cheap and of requiring virtually no maintenance. Since transformer oil is incompressible, with a sealed arrangement it is necessary to provide space above the oil, filled with either dry air or nitrogen, to act as a cushion for expansion and contraction of the oil. Without this cushion the tank internals would experience very large changes of pressure between the no-load and the loaded condition. (To some extent, this problem is reduced if the transformer has a corrugated tank, see below.) These pressure variations can cause joints to leak so that external air is drawn in at light load conditions, usually bringing in with it moisture or even water, or they can cause dissolved gas in the oil to be brought out of solution and thus form voids leading to internal electrical discharges and ultimate failure. The more sophisticated or strategically important sealed transformers are provided with a pressure gauge which shows an internal positive pressure when the transformer is loaded, thus indicating that the seal remains sound.


FIG. 98 Three-phase 200 kVA, 11 kV, 50 Hz pole-mounted transformer showing a corrugated tank (Bonar Long Ltd)

Corrugated tanks

A convenient way of providing some means of accommodating expansion and contraction of the oil as well as dissipating losses from small sealed distribution transformers is to use a corrugated tank as shown in FIG. 98. The corrugations are formed from light gauge steel. They may be from 80 to 200 mm deep and about 400 mm high at about 20 mm spacing, thus forming the sides of the tank into cooling fins. The top and bottom edges are seam welded and the fins are able to expand and close-up concertina fashion as the tank internal pressure varies, thus absorbing some of the pressure variation. The system is not without its disadvantages; it is necessary to maintain a high level of quality control on the seam welded fin edges and, because of the thin gauge of the metal used, a good paint protective treatment is necessary. This might not be readily achieved if the fins are too deep and too closely spaced. To minimize these problems it is considered that the material thickness should be no less than 1.5 mm.

Gas and oil actuated relays

As mentioned above, the provision of a conservator also permits the installation of a Buchholz relay. This is installed in the run of pipe connecting the conservator to the main tank. In this location, the relay collects any gas produced by a fault inside the tank. The presence of this gas causes a float to be depressed which is then arranged to operate a pair of contacts which can be set to 'alarm', or 'trip', or both, dependent upon the rate of gas production. A more detailed description of this device will be found in the section dealing with transformer protection (Section 6.6). In order to ensure that any gas evolved in the tank is vented to the conservator it is necessary to vent every high point on the tank cover; for example, each bushing turret, and to connect these to the conservator feed pipe on the tank side of the Buchholz relay, normally using about 20 mm bore pipework. The main connecting pipe between tank and conservator is 75 or 100 mm bore, depending upon the size of the transformer.

Bushing connections

A bushing is a means of bringing an electrical connection from the inside to the outside of the tank. It provides the necessary insulation between the winding electrical connection and the main tank which is at earth potential. The bushing forms a pressure-tight barrier enabling the necessary vacuum to be drawn for the purpose of oil impregnation of the windings. It must ensure freedom from leaks during the operating lifetime of the transformer and be capable of maintaining electrical insulation under all conditions such as driving rain, ice and fog and has to provide the required current carrying path with an accept able temperature rise. Varying degrees of sophistication are necessary to meet these requirements, depending on the voltage and/or current rating of the bushing. FIG. 99 shows an 11 kV bushing with a current rating of about 1000 A. This has a central current carrying stem, usually of copper, and the insulation is provided by a combination of the porcelain shell and the transformer oil. Under oil, the porcelain surface creepage strength is very much greater than in air, so that the 'below oil' portion of the bushing has a plain porcelain surface. The 'air' portion has the familiar shedded profile in order to provide a very much longer creepage path, a proportion of which is 'protected' so that it remains dry in rainy or foggy conditions.

At 33 kV and above, it is necessary to provide additional stress control between the central HV lead and the external, 'earthy' metal mounting flange.

This can take the form either of an s.r.b.p. multifoil capacitor or of an oil impregnated paper capacitor of similar construction. This type of bushing is usually known as a condenser bushing. FIG. 100 shows a 400 kV oil impregnated paper bushing in part section. The radial electrical stress is graded through the insulant by means of the concentric capacitor foils and the axial stress is controlled by the graded lengths of these. The capacitor is housed between an inner current conducting tube and the outer porcelain casing which is in two parts, the upper part is a weatherproof shedded porcelain and the lower part (the oil-immersed end) is plain porcelain. The interspace is oil-filled and the bushing head, or 'helmet', provides oil-expansion space and is fitted with a prismatic sight glass to give indication of the bushing oil level. This head also allows space for an air or gas cushion to allow for expansion and contraction of the oil. This expansion space must be adequately sealed against the ingress of atmospheric air (and hence moisture) and it is usual in such designs to incorporate a spring pack, housed in the top cap, to maintain pressure loading on gasketed joints whilst allowing for expansion and contraction of the different components during temperature changes.


FIG. 99 11 kV bushing


FIG. 100 400 kV oil-impregnated paper bushing

Clearly, this type of bushing is designed for installation at, or near, the vertical position. The bushing illustrated is of the so-called 're-entrant' pattern in that the connection to the line lead is housed within the lower end of the bushing. This has the effect of foreshortening the under-oil end of the bushing but requires a more complex lower porcelain section which adds consider ably to the cost. In order to make the electrical connection to the bushing, the HV lead terminates in a flexible pigtail which is threaded through the central tube and connected inside the head of the bushing. In some higher current versions the pigtail is replaced by a copper tube, in which case it is necessary to incorporate some flexible section to accommodate relative movement, thermal and mechanical, between the transformer internals and the head of the bushing.

This must be capable of withstanding the mechanical vibration and of carrying the maximum rated current of the transformer. The heavy insulation on the line lead is only taken just inside the re-entrant end of the bushing. With this arrangement, an inverted conical section gas-bubble deflector must be fitted beneath the re-entrant end of the bushing to ensure that any gas evolved within the transformer tank is directed to the Buchholz relay and not allowed to collect within the central stem of the bushing.

Versions of 400 kV oil-impregnated paper bushing have been developed in which the under-oil porcelain is replaced by a cast epoxy-resin section. This material is able to withstand a higher electrical creepage stress under oil than porcelain which thus allows a plain tapered profile to be used instead of the re-entrant arrangement. With this type of bushing the transformer lead can be connected directly to a palm at the lower end of the bushing as shown in FIG. 101.

The most recent development in EHV bushings is to replace the oil impregnated paper capacitor by one using epoxy-resin-impregnated paper (frequently abbreviated to e.r.i.p.). These bushings were originally developed for use with SF6 but are now widely used for air/oil interfaces. These bushings still retain porcelain oil-filled upper casings, since it is difficult to find an alternative material with the weathering and abrasion resistance properties of porcelain, but the under-oil end is totally resin encapsulated.

In most EHV bushings provision is made for accommodation of a number of toroidally wound current transformers by incorporating an earth band at the oil immersed end just below the mounting flange. The bushing is usually mounted on top of a 'turret' which provides a housing for the current transformers and the arrangement is usually such that the bushing can be removed without disturbing the separately mounted current transformers. The current transformer secondary connections are brought to a terminal housing mounted on the side of the turret.

In 400 and 275 kV bushings, the designer's main difficulty is to provide an insulation system capable of withstanding the high working voltage. The LV bushings of a large generator transformer present a different problem. Here, the electrical stress is modest but the difficulty is in providing a current rating of up to 14 000 A, the phase current of an 800 MVA unit. FIG. 102 shows a bushing rated at 33 kV, 14 000 A. The current is carried by the large central cop per cylinder, each end of which carries a palm assembly to provide the heavy current connections to the bushing. The superior cooling capability provided by the transformer oil at the 'under-oil' end of the bushing means that only two parallel palms are required. At the air end of the bushing, it is necessary to pro vide a very much larger palm surface area and to adopt a configuration which ensures a uniform distribution of the current. It has been found that an arrangement approximating to a circular cross-section - here, octagonal - achieves this better than one having plain parallel palms. These palms may be silver-plated to improve their electrical contact with the external connectors, but if the con tact face temperature can be limited to 90ºC a more reliable connection can be made to plain copper palms, provided that the joint is made correctly.

========


FIG. 101 Arrangement of connection of transformer 400 kV HV lead to lower end of epoxy-resin-impregnated paper (e.r.i.p.) bushing

Upper end of capacitor is contained in shedded porcelain housing similar to that shown in FIG. 98

Mounting flange

Central earthed band for accommodation of current transformers

Lower end of epoxy-resin impregnated paper capacitor

Bushing lower terminal palm connected to central stem Paper covered HV lead from transformer winding

Aluminum spinning provides electrical stress shielding for connection

========


FIG. 102 Simplified cross-section of a 33 kV, 14 000 A bushing

Insulation is provided by an s.r.b.p. tube and, as can be seen from the diagram, this also provides the means of mounting the flange. External weather protection for the air end is provided by the conventional shedded porcelain housing. Where the bushing is to be accommodated within external phase isolated connections an air-release plug on the upper-end flange allows air to be bled from the inside of the assembly, so that it can be filled with oil under the head of the conservator.

SF6 connections

With the introduction of 400 kV SF6-insulated metalclad switchgear into the UK in the late 1970s, the benefits of making a direct connection between the switchgear and the transformer were quickly recognized. At the former CEGB's Dinorwig power station, for example, transformers and 400 kV switchgear are accommodated underground. The transformer hall is immediately below the 400 kV switchgear gallery and 400 kV metalclad connections pass directly through the floor of this to connect to the transformers beneath. Even where transformers and switchgear cannot be quite so conveniently located, there are significant space saving benefits if 400 kV connections can be made direct to the transformer, totally enclosed within SF6 trunking. FIG. 103 shows a typical arrangement which might be used for the connection of a 400 kV generator transformer. The 400 kV cable which connects to the 400 kV substation is terminated with an SF6 sealing end. SF6 trunking houses line isolator, earth switch and surge diverter. By mounting the 400 kV SF6/oil bushing horizon tally, the overall height of the cable sealing-end structure can be reduced.

The construction of the 400 kV SF6/oil bushing is similar to that of the air/ oil bushing described previously in that stress control is achieved by means of an e.r.i.p. capacitor housed within a cast resin rather than a porcelain shell.

The 'under oil' end is 'conventional', that is it is not re-entrant and, since there is no need for the lengthy air-creepage path used in an air/oil bushing, the SF6 end is very much shorter than its air equivalent.


FIG. 103 Simplified arrangement of 400 kV SF6 connection to generator transformer

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.

Disadvantages

• 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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