reading / British practice / Vol D - 1990 (ocr) ELECTRICAL SYSTEM & EQUIPMENT

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s.NGLE CORE powER SUPPLY

VIEW ON FRONT WITH LID REMOVED

al 114V cable box

ENTRANCE PORT

FOR MATING

I /kV BUSHONG

POINT

I NSULATION

CONDUCTOR

CONNECTOR

INTERNAL

SCREEN

EARTHING

LUG

01 1 1 kV elaslimoal elbow

FIG. 3.41 11 kV cable box and section of 11 kV elastimold elbow termination

joint, this is finally covered by the semiconducting moulded-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, it is CEGB practice to enclose the termination within a non-magnetic sheet steel box to provide 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.

1.6.6 Tank- mounted coolers

Tank-mounted radiators represent the simplest option for cooling smaller power station transformers. These are suitable for all auxiliary transformers from the smallest in common use (about 0.8 MVA), to the largest, which are usually 12.5 MVA, 11/3.3 kV. 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 in and out of the radiators via the headers and is cooled as it flows downwards through the thin sheet-steel passes. The arrangement is generally considered to be suitable only for transformers having natural oil and natural air circulation, i.e., ONAN cooling, as defined in BS171.

It would be possible to suspend a fan below the radiators to provide a forced draught, ONAF arrangement.' At best this might enable the transformer rating to be increased some 10-15 070, but only at the extra cost and complexity of control gear and cabling for, say, two fans. Achievement of this modest uprating would require that the radiators be grouped in such a 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. In addition, to provide space below the radiator for installation of a fan requires that the length of the radiator must be reduced, so that the area for selfcooling is reduced.

It is frequently a problem to accommodate tankmounted 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. 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-assem- bled, is lost.

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 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 seaside sites. The CEGB, therefore, now specifies that plate-type radiators for power station transformers must be hot-dip galvanised in the manufacturer's works prior to receiving an etchprime, followed by the usual paint treatment in the works.

1.6.7 Separate cooler banks

As already indicated, one of the problems with tankmounted 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 draught or induced draught fans, and, as was indicated in Section 1.4.11 of this chapter, the greater benefits are gained by forcing and directing the oil flow.

However, many utilities, particularly in the USA, do make use of tank-mounted radiators for very large transformers and it might, therefore, be worthwhile considering the merits and disadvantages of these in relation to the separate free-standing cooler arrangement favoured by the CEGB.

Advantages

•More compact arrangement saves space on site.

•Can be transported as a single entity, which considerably reduces site-erection work.

•Allegedly cheaper due to saving of pipework and headers and frame/support structure.

Disadvantages

•Forced-cooling must usually be restricted to fans only, due to the complication involved in providing a pumped system.

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

•A noise-attenuating enclosure cannot be fitted 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 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, i.e., station and generator transformers especially since, in order to allow free access for cooling air, these must be located in an open situation.

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 favour of freestanding cooler banks, it is appropriate to consider the merits and disadvantages of forced as against natural cooling for power station use.

Adopting OFAF cooling for say, a 60 MVA station 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, there is slightly-poorer reliability in. a transformer which relies on other auxiliary equipment, compared with an ONAN transformer having no electrically-driven auxiliaries. On the credit side, there is a considerable reduction in the plan area of the cooler bank, resulting in significant space saving of the overall layout. Such an OFAF-cooled station transformer is rated to deliver full output for the start-up of a unit during an outage on the second station transformer, so that 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 unit transformer is required to operate at or near to full output 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 layout to enable it to be totally naturallycooled.

If a transformer is provided with a separate freestanding cooler bank, it then becomes 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 minimise 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 by-pass the transformer tank. Normally this would be achieved by incorporating a non-return valve in each branch. However, such a valve would create too much head loss to allow the natural circulation necessary to provide an ONAN rating. The solution is to use a flapvalve of the type shown in Fig 3.42, 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.

1.6.8 Water cooling

In the past, water was a common choice of coolant medium for many power station transformers, including practically all generator transformers and most station and unit transformers. This was logical, since there is an ample source of cooling water available in the vicinity of these transformers and oil/water heat exchangers are compact and thermally efficient. Such an arrangement does not provide for a self-cooled rating, since the head loss in oil/water heat exchangers precludes natural oil circulation, but (as explained above) a self-cooled rating is only sensible for the station transformer. The provision of a cooling water

FLOW DIREOTtON

Ftc. 3.42 Oil flap-valve

supply appears to be low cost compared with the cost of running and providing fans, so that water cooling often appears to be more economical.

The precise cost of cooling water depends on the source, but 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 number of major generator transformer failures attributable to water entering the oil through cooler leaks, the CEGB reassessed the philosophy of water cooling. The high cost of these failures, 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 a forced-air cooled arrangement for the Littlebrook D generator transformers and this has since become the standard, whenever practicable.

The risk of water entering the transformer tank due to a cooler leak has long been recognised and 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.

In the past, it was the 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 prevents the flow, full pressure will be applied to the system.

From the above arguments, it has become policy to avoid water cooling as far as practicable. When it is considered essential, special measures are taken to provide an installation of the appropriate integrity. One recent example is the Dinorwig pumped-storage power station where the generator transformers are located underground, making air cooling impracticable on grounds of space and noise. Figure 3.43 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

S.19U.IJOISUE'Ji

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 gener- ously-sized overflow is provided so that, if this valve should stick open, the header tank will not become pressurised. The position of the water pump in the circuit and the direction of flow is such that should the water outlet valve lf the oil/water heat exchanger be inadvertently closed, this too would not cause pressurisation 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 might be justified are those in which the ambient air temperature is high, so that a significantly greater temperature rise of the transformer might be permitted if water cooling is employed. Such an installation 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 3.44, 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 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, tita- nium-tubed coolers. This is usually less economic than a double-tubed/double-tubepiate 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 minimised 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 errosion.

If the cooling medium is seawater, 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 CEGB stations, but it is important to recognise 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.

A fan and its control equipment can operate continuously or under automatic control for periods of two 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 within the CEGB 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 most advisable to provide a spare cooler and standard practice has, therefore, been to install three 50 0/o-rated coolers, one of which will be kept in a wet standby condition, i.e., with inlet and outlet valves closed but full of clean water, and with the other two in service.

The subject of water cooler design and operation is dealt with more fully in Volume C.

1.6.9 Cooler control

Ancillary plant to provide forced cooling must be provided with power supplies and a means of control. At its most basic, this simply takes the form of manual switching at a local marshalling panel, housing auxiliary power supplies, fuses, overloads and contactors. On modern power stations, 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 halves, using two 50%o-rated pumps and two sets of fans. Plant failure would thus normally not result in loss of more than half of the forced cooling. As has been explained in Section 1.6.7 of this chapter, many forced-cooled station transformers and, in some cases, unit 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%o-rated duty and standby pumps, as shown in Fig 3.45, is now favoured. 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 will have virtually no self-cooled rating, so that pumps can be initiated from a voltage sensing relay, fed from a voltage transformer

which is energised whenever the generator transformer is energised. 100 07o-duty and standby pumps are provided, with initiation of the standby pump should flow-failure be detected on the duty pump. Fans can 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 80 ° C and out at 70 ° C. The second

group is switched on at 95 ° C and out at 80 ° C. 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 30°C. The control scheme also allows each pump to serve either in the duty or standby mode and the fans to be selected for either first-stage temperature operation or second-stage operation. In addition, a multiposition mode selector

of supply. This normally leads to transformers being located in two groups.

The first group consists of those located immediately outside the turbine hall. This includes the generator transformer in order to minimise the length of the very heavy-current generator connection and almost certainly the unit transformer also. The generator busbars are large aluminium fabrications which, for reasons of site installation, must be kept as straight and as simple as possible. Those supplying the unit transformer are teed-off the main run; although not having as large a load current as those to the generator transformer, the current under fault conditions is greater than that in the main run, since both the system and the generator contribute. To minimise the likelihood of faults, as well as to limit the cost of these connections, it is desirable that they should be kept as short as possible.

The subject of generator main connections is dealt with more fully in Chapter 4.

The LV current of the unit transformer is of the order of twice that on its HV side and usually involves the use of very bulky 11 kV cables to connect to the 11 kV switchgear. To keep these cables as short as possible, the 11 kV unit board is normally placed close by. The same 11 kV switchgear annexe might also house the 11 kV station board, suitably segregated from the unit board, hence its station transformer could also be included in this group provided that, as an alternative source of 11 kV supplies, it too can be fully segregated against any incident which might affect the unit transformer.

Recent segregation requirements introduced for nuclear stations now require the station transformer to be removed to a more distant location. This is so that alternative 11 kV supplies can be preserved, even in the event of a major incident, such as an aircraft crash on the site.

Grouping these main transformers together has the advantage that they can share drainage facilities and, since transformer compound drainage involves costly civil works, this is a worthwhile economy. Figure 3.46 shows a typical layout of generator unit and station transformers for two units of a four-unit station.

Oil-filled transformers represent a fire hazard. To ensure rapid extinguishing of any fire, each transformer is provided with a fixed waterspray fire protection installation. This consists of a system of spray nozzles located around the transformer and directed towards it which provide a total deluge when initiated, usually by the bursting of any one of a series of glass detector bulbs placed around and above the transformer. Another part of the strategy for rapid extinguishing of a fire is the removal of any spilled oil from the plinth as rapidly as possible. To assist with this, its surface must be smooth concrete. Large drainage trenches are provided and these must have an adequate fall. Clearly large quantities of oil and water cannot be allowed to enter the normal drainage system, so the drainage trenches are taken to interceptor chambers which allow settlement and separation of the oil before allowing the water to be led away. A typical arrangement for a four-unit station is shown in Fig 3.47. Although the plinths are designed to drain rapidly, it is important to ensure that any water which might be contaminated with oil is not allowed to flood into neighbouring areas, so each plinth must be contained within a bund wall which will hold, as a minimum, the total contents of the transformer tank, plus five minutes operation of the fire protection, and this after heavy rain has fallen onto the area.

Until quite recently, the standard method of ensuring rapid removal of oil from the surface of the transformer plinth was to install the transformer on dwarf walls, perhaps one metre high, the plinths then con-

sisting of open mesh about 100 mm below the level of the top of the wall covered with large chippings. Any spilled oil passed through the chippings and the mesh into the chamber below. Such an arrangement allowed burning oil to be led from the surface very rapidly and the fire was quickly extinguished when the chippings were new and in a fairly clean condition. However, it became clear that chippings which had become oily over the years and had acquired a coating of grime, tended to act as a wick in the event of a fire and made it more difficult to extinguish. Figure 3.48 shows the layout of the main transformer plinth at Heysham 2 power station. The generator transformer is a threephase bank of single-phase units. Each phase has both ends of the LV winding brought out to a pair of LV connections side-by-side on one side of the tank. These are connected in delta by means of a phase-isolated air-insulated connection, similar in construction to the main connections to the generator which are themselves teed-off from each corner of this delta. Because of the difficulty in making angled welds, and of designing right-angled turns in the heavy low-voltage connections, it is desirable that these be run as straight as possible, so ideally the generator transformer should face squarely onto the end of the generator. Unit transformer tee-offs can then, if physically possible, tall vertically onto the unit transformer placed beneath the connections and behind the generator transformer. It is important to ensure that each phase of the generator transformer (as well as those of the unit transformer) can be installed and removed with the

minimum disruption to cabling, connections, and to its neighbours. The routes for installation and withdrawal are indicated on the diagram. It should be noted also that the generator transformer cooler, with about 2 MW of losses to dissipate at full-load, is located so that it has at least eight times its plan area of free space around it to ensure an adequate cooling-air supply, with no recirculation.

The layout of generator and unit transformers, in particular, must have regard to correct phase-relation- ships. Although this is true for all transformers, it is the bulky and less flexible arrangement of the connections which makes this so important for these two transformers. This design task is fraught with pitfalls, and incorrectly phased connections can be exceedingly expensive to unscramble. The important convention is that contained in BS171, that the phases A, B and C (or U, V and W) run from left to right when viewed from the HV side of the transformer, but LV terminals are reversed when viewed from the generator. The other conventional rule is that, within a particular winding, the low-numbered connection goes to neutral and the higher-numbered connection goes to the terminal. Referring to Fig 3.49 and recalling that, as indicated in Section 1.1.2 of this chapter, the standard phasor grouping for a 400/23.5 kV generator transformer is Ydl, the star point of the HV winding will be A], B1, C1 and the LV will require a2 to be connected c1, b2 to al and c2 to b1, with a2 becoming terminal a, b2 terminal b, and c2 terminal c. For the simplest arrangement of LV connections, it can thus be seen

from Fig 3.49 (b) that terminal 2 of the LV winding will require to be on the right, when viewed from the LV side. Figure 3.49 (b) also shows the arrangement of generator connections required to give red, yellow, blue to phases a, b and c, respectively.

The second group of transformers requiring to be accommodated in the station layout are those stepping down II kV supplies to 3.3 kV and from 3.3 kV to 415 V. Whilst it is permissible for 11 kV cabling to be used. to distribute power for considerable distances around the site, supplies at lower voltages must be placed as close as possible to their loads. Ideally, these transformers should be in the middle of the station. This is not practical for many reasons, not least that oil-filled transformers represent a fire hazard. Often in a coal-fired station, the best compromise is to place them alongside the boiler house, between it and the precipitators. Figure 3.50 shows an outline plan of a two-unit coal-fired station with

the location of outdoor 11/3.3 kV and 3.3/0.415 kV transformers identified. Many nuclear stations have separate reactor and turbine buildings, so that transformers can be placed alongside a roadway between them. If the station has only one or two units, often the best location will be to the side of the turbine hall and steam generating plant buildings. Figure 3.51 shows where these transformers might be located in a nuclear station.

For all of these possible locations, consideration must be given to:

•Clear access for installation and for future removal should this become necessary.

•Access for cabling.

•The need for fire fighting provision and ensuring that adjacent buildings and plant are not placed at risk if a fire occurs.