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

be checked for gas content and taken as the starting

point.

•M1 control, alarms, protection and cooler gear checked for correct operation. Protection trips set

to appropriate level for initial energisation.

•Tank and cooler earth connections checked as well as the earthing of the HV neutral, if appropriate.

2 Special design features

whilst the foregoing sections have examined those features which most power station transformers have in common, the following sections take a closer look at each class of transformer to examine those aspects which are special for its particular duty.

2,1 Generator transformers

2.1.1 Required characteristics

The generator transformers, in most present day stations will have a voltage ratio of 23.5/400 kV. The rating must be sufficient to allow the generator to export its full megawatt output at 0.85 power-factor lagging or 0.95 power-factor leading or, alternatively, half of full megawatt output at 0.7 power-factor lead.

Some early 660 MW generators were designed to deliver full output at 0.8 power-factor which, making due allowance for the power requirements of the unit board, led to a maximum output power of 800 MVA so that for the sake of standardisation the generator transformer rating has been fixed at this level.

The important criteria which influence the generator transformer design are as follows:

•The HV volts are high — usually 400 kV.

•The LV current is high — almost 20 000 A for an 800 MVA transformer.

•The impedance must be lower than that resulting from the simplest design for this rating — a figure of about 16% is specified and variation with tap position must be kept to a minimum to simplify system design and operation.

•An on-load tapchanger is required to allow for varia-

tion of HV system volts and generator power factor. LV volts will remain within +5 070.

•The transport weight must be within the limits laid down by the transport authorities and the available transport vehicles.

•Reliability and availability must be as high as possible, since without the generator transformer unit output cannot be made available to the national grid and the replacement generation cost of an outage is high.

There are also a number of other criteria which although less important will also have a bearing on the design. These are:

•Because of the high load-factor, both load and no-load losses must be as low as possible.

•In view of the direct connection to the 400 kV system. a high impulse strength is required.

•Noise level must be kept below a specified level.

•Very little overload capability is necessary. A figure of 4% overload for three one-hour periods per day is normally specified.

2.1.2 General design features

The extensive list of required characteristics given above places considerable constraints on the design of the generator transformer. For a transformer of 800 MVA, 400 kV, the most limiting factor is that of transport weight. The high HV voltage requires large internal clearances which means increasing size and, as can be seen from the expression for leakage reactance in Section 1.3.2. of this chapter, increased HV to LV clearance has the effect of increasing the reactance, and hence the impedance. This tendency to increase reactance would normally be offset by an increase in the axial length of the winding but, for a large generator transformer, the stage is soon reached where further increases cannot be obtained because of the limit on transport height.

A significant reduction in leakage reactance for given physical dimensions can be obtained by adopting an arrangement of windings known as 'split-concentric'. This is shown in Fig 3.56 (a). The HV winding has

(a) Spill concenIrc winclog arrangement

LEAKAGE FL

FIG. 3.56 Split-concentric winding arrangement

been split into two sections, with one placed on either side of the LV winding. This is not too inconvenient for .a transformer with graded HV insulation, since the inner HV winding is at lower potential and can therefore be insulated from the earthed core without undue difficulty. The reason why this arrangement reduces leakage reactance can be seen from Figs 3.56 (b) and (c), which (.ii‘e plots of leakage flux both for si mple concentric and split concentric arrangements having the same total MMF. It can be shown that the leakage reactance is proportional to the area below the leakage flux curve, which is significantly less in the split-concentric design. The price to be paid for this method of reducing the leakage reactance which, in reality, means reducing the physical size for a given rating, is the complexity involved in the increased number of windings, increased number of leads, and increased sets of interwinding insulation. For simplicity, the tapping winding has not been shown in Fig 3.56 (c). With this split-concentric arrangement, the taps are usually accommodated in a separate winding below the inner HV winding. As taps are added or removed, the ratio of the HV split is effectively varied and this has the effect of producing relatively large changes in leakage reactance. This undesirable feature is a further disadvantage of this form of construction.

Throughout the 1960s, at the time of building most of the 500 MW units, the split-concentric arrangement was the most common form adopted for 570 MVA and 600 MVA three-phase generator transformers. It enabled these transformers to be transported threephase within limits of about 240 t transport weight and 4.87 m travelling height, albeit most of them had very high flux densities and losses in order to keep the material content to the minimum. In fact, a transformer of 735 MVA, three-phase, although its HV winding was only 275 kV, was transported within these li mits to Hartlepool power station. However, at the ti me of the adoption of the 660 MW unit size for Drax power station at the end of the 1960s, it was decided to make the transition to single-phase units. These have many advantages and will be described in greater detail in the following section.

2.1.3 Single-phase generator transformers

With the adoption of single-phase construction, transport weight for 800 MVA and probably even larger transformers ceases to impose any significant constraint on the transformer designer. Travelling height continues to impose some restriction, but the designer is usually able to deal with this without undue difficulty. Figure 3.57 shows various arrangements of core and windings that can be adopted for single-phase transformers. In Fig 3.57 (a), the core has one wound limb and two return yokes. Alternatively, both limbs could be wound, as shown in Fig 3.57 (b), but this increases the cost of the windings and also the overall height, since the yoke must be full-depth. It would be possible to

reduce the yoke depth by providing two return yokes as in Fig 3.57 (c) but this adds further complexity and is therefore rarely advantageous. Some manufacturers reduce the yoke depth still further by using four return yokes (Fig 3.57 (d)). Figure 3.58 shows the core and windings of a CEGB single-phase 23.5/400 kV generator transformer having one limb wound and with four return yokes. This has a transport weight of 185 t and a travelling height of 4.89 m. The arrangement of Fig 3.57 (a) is also used for some CEGB single-phase generator transformers.

A further benefit of single-phase construction is that should a failure occur, it is very likely to affect one phase only, so only that phase need be replaced and, being more easily transported, spare single-phase units can be kept at strategic central locations which can then serve a number of power stations. This led to the concept of interchangeable single-phase generator transformers which were developed for the majority of the 660 MW units. For this the electrical characteristics of impedance and voltage ratio must be closely matched on all tap positions and, of course, the physical sizes and arrangements of connections for HV and LV windings must be compatible. Each single-phase unit must have its own on-load tapchanger, driven from a single drive mechanism mounted at the end of the bank. Tapchangers must thus be compatible in that all must drive in the same sense and all must have the same number of turns for a tap change. The tapchangers must be located so that the drive shafts will align. The location of inlet and outlet cooling oil pipes must correspond on all units. Figure 3.59 shows the arrangement of an 800 MVA bank of single-phase units and details all the items which must align to provide complete interchangeability.

Both ends of each winding of a single-phase unit are brought out of the tank so that the NV neutral has to be connected externally, as well as the LV delta. The former is arranged by bringing the earthy end of each HV winding to a bushing terminal mounted on the top of the tapchangers. These can then be solidly connected together by means of a length of copper bar, suitably connected to the station earth.

On the early single-phase banks, the LV delta was connected by means of an oil-filled delta box which spanned the three tanks. This can be identified in Fig 3.59. It was split internally into three sections by means of barrier boards so that the oil circuits of the three tanks were kept separate. It was recognised that phase-to-phase faults were possible within the delta box and that greater security could be obtained by the use of an external air-insulated phase-isolated delta which was, in fact, an extension of the generator main connections. This is now the standard arrangement, so that the LV connections to each single-phase unit are made via a pair of bushings mounted on a pocket on the side of the transformer tank. The use of airinsulated phase-isolated delta connections has the added' advantage that it enables the oil circuits of the three

phases to be kept entirely separate, so that, in the event

of a fault on one phase, there will be no contamination of the oil in the other phases.

The HV connections may be via air bushings or

SF6-insulated metalclad trunking. The interface is therefore the mounting flange on the tank cover, as can be seen from Fig 3.59.

Figure 3.60 shows an 800 MVA generator trans-

former bank installed at Drax power station before erection of the acoustic enclosure.

2,1.4 Performance and reliability

The generator transformer is the one transformer on

a power station for which no standby is provided. It must be available for the generator output to be connected to the grid. For a high merit unit, high reliability is required. If its output were lost, this would necessitate running less efficient plant which is more expensive to operate.

It is difficult to set down design rules for high reliability. Design experience may identify features which might detract from reliability but it is difficult to be sure that every potential source of trouble has been avoided. Large generator transformers are produced in small numbers, so there are no large production runs which can be used to eliminate teething troubles. One factor which can aid reliability, therefore, is to

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repeat tried and proven designs wherever possible, even os.er many years, thus reducing the occasions on which teething troubles might occur.

Another design rule for high reliability is to 'keep it si mple'. This is not easy for an item as sophisticated as a large generator transformer but, nevertheless, as explained in Section 2.1.2 of this chapter, a degree of si mplification was achieved by the change from threephase to single-phase units. This also meant that there Nas no longer the same emphasis on keeping sizes and weights to an absolute minimum and so there vras a consequent relaxation of the pressures which threatened reliability .

In view of the importance of high reliability of generator transformers, the CEGB gave special attention to the subject in the 1970s in the light of op-

erating experience on the 570 and 600 MVA units following a series of failures. It was recognised that the occurrence of teething troubles on new designs was having a significant effect on the reliability of these units. Study of the operating failures showed that reliability was likely to be poorer with new designs during their early life. Furthermore, design changes tended to be introduced frequently due to the practice of designing for lowest total cost taking into account the changing cost of losses (see Section 2.1.5 of this chapter). It was decided that, although it was not possible to have long production runs which might eliminate the teething troubles associated with new designs, it was possible to limit the number of new designs which were introduced, particularly since a single standard rating of generator of 660 MW had

been adopted. Accordingly in 1979, the CEGB intro-

duced the concept of Registered Designs whereby manufacturers agreed that they would submit detailed tech-

nical parameters and schedules of all manufacturing d rzw.ines, including details of revision of issue, to describe their current design of 267 MVA 23.5/400 kV sinule-phase generator transformer, which should pre- :cr abl ,. have been successfully tested and in operation a t a CEGB )ower station. These particulars then became that n anufacturer's registered design particulars and, for future stations, changes to these would aril % be allowed if it could be demonstrated that a definite improvement in reliability would result, or ■k.erc unavoidable due to the non-availability of some ten' required for manufacture. Design change in the interest of further competitiveness was not acceptable.

After more than seven years of operating the re- ,istered design scheme, which has only been applied to his one rating of generator transformers, there are clear indications that these transformers are achieving a very much higher reliability than their predecessors. It cannot, of course, be claimed that this is solely due to the registered design system, since the other factors mentioned in this section, aS well as the more exten- ,,i% e testing procedures described in Section 1.7 of this chapter, are all likely to have contributed.

The CEGB is aware of the possible consequences i mplied in the registered design procedure that designs inight become 'fossilised'. It is considered, however, that by allowing changes that can be shown to improve reliability, a mechanism for worthwhile development exists which will act as a safeguard against this.

2.1.5 Economics of operation

II the generator of a high-merit unit is unavailable for any reason, making it necessary for less efficient plant to operate instead, then there will be extra costs to the system equal to the difference in operating costs for the failed and the replacement units. A major failure which necessitates the removal of a single-phase unit and the substitution of a spare would result in an outage of several weeks which could incur additi onal operating costs equal to the first cost of the Transformer. This helps the subject of reliability to be seen in context.

There are, however, other costs associated with opation of a transformer. These may be considered on

an annual basis and consist of:

assumed that whenever the generator 'transformer of a [nett merit unit is energised, it will operate at full-load.

It is therefore necessary to supply iron losses, load losses and cooler losses in total. These have an annual

cost based on the annual capital cost of installing the

necessary replacement generating capacity and a running cost which reflects the 'amount of energy consumed, i.e., having the form:

where P = total losses, kW

A = capacity charge, E/kW

d = energy charge, pence/kWh

k = factor which reflects the fact that the unit will not generate for 365 days/year and is about 0.72

p = an amortisation factor whose derivation is given below

The purchase of a transformer involves the spending of money which either has to be borrowed or which could earn income, if invested. At the end of n years, the borrowed money has to be repaid or, alternatively, enough money will have to be saved to replace the asset.

The amortisation factor p is given by:

where r Wo is the real rate of return on capital, i.e., the rate in excess of inflation. This is set as a target 'test discount rate' by the Government when economic policies for nationalised industries are appraised from ti me to time.

Loss assessment To assess whether it is justifiable to spend additional capital, £ AC, to reduce losses, it is necessary to show that:

This can be illustrated by an example as follows:

From Equation (3.7) amortisation factor p is given by:

1.1 20

0.1 x = 0.1175 (1 . 120_ 1)

Abalance in Equation (3.8) occurs when AC x 0.1175 = (120 x 0.1175)

+(0.024 x 8760 x 0.72)

figure of £1408 , kW and any expenditure greater than his for a saving of one kilowatt of loss cannot be justified.

It should be noted that the numbers used in the above example have been provided for the purposes of illustration. Whilst at the present time they reflect with reasonable accuracy the values which would be actually used within generation construction, in times of high inflation they may change considerably. It might also be recognised, however, that the value of £1408/kW which has been derived, is considerably less than the figure which is used by many authorities even at the present time. The reason for this is the value of test discount rate used; it will be seen that if the above calculation is repeated with a value of test discount rate set at 5 070, a figure used by some authorities, a loss value of about £2000/kW will be deduced. The effect of the higher test discount rate, therefore, is to place a lower value on losses and to sway assessments towards acceptance of lower initial capital cost options.

Further indication of the significance of the cost of losses can be gained by considering a specific transformer associated with a 600 MW unit. This might have total losses of 2 MW and a first cost of £2.5 million.

Capitalising the losses at the figure of £1408/kW puts their value at £2.8 million; it can be seen that the saving from a reduction of a few per cent in losses is very significant.

Because this calculation can be so easily performed, it is tempting for accountants to demand that it be carried out whenever the purchase of a new transformer is contemplated. In the 1960s, when energy and material costs as well as interest rates were changing rapidly, and by differing amounts in relation to each other, rapid changes in loss capitalisation values were common. This was one of the pressures for the introduction of new designs which were not warranted on purely technological grounds. Hence the CEGB introduced the registered design concept described in Section 2.1.4 of this chapter, and the decision was taken that a loss-capitalisation calculation would not be carried out as part of the tender assessment process for 800 MVA transformers so that manufacturers were not encouraged to change designs in the interests of Lompetitiveness. Since different manufacturer's designs did not actually have the same losses, the design having the highest losses might appear to have an unfair advantage, since it might be expected to contain least material. However, this was not considered to be significant for the variation in losses which occurred in

practice, and operation of the registered design procedure for a number of generator transformer tenders has supported this view.

2.2 Station transformers

2.2.1 Station transformer characteristics

The station transformer supplies the power , station auxiliary system for starting-up the boiler/turbinegenerator unit and for supplying those loads which are not specifically associated with the generating unit, for example, lighting supplies, cranes, workshops and other services. In addition, in order to provide a diversity of supplies to certain plant, the station switchboard is used as a source of supply for certain large drives which are provided on a multiple basis for each unit, for example, the gas circulators of a nuclear reactor and the circulating water pumps for the main condensers. The station transformer is usually the first major connection with the grid for a power station under construction, providing supplies for the commissioning of the plant.

The design criteria to be met by the station transformer are as follows:

•The HV connection is from the 132, 275 or 400 kV grid system.

•On the most recent, larger units, the LV is invariably 11 kV nominal.

•Impedance must be such that it can be paralleled with the unit transformer at 1I kV without exceeding the permissible fault level — usually about 15%.

•An on-load tapchanger is required to maintain 11 kV system volts constant as load is varied and as grid voltage varies.

•Operating load-factor is low, i.e., for much of its life the station transformer will run at half-load, or less. Load losses can therefore be relatively high, but fixed losses should be as low as possible.

2.2.2 General design features

As explained in Section 1.1.2 of this chapter, the station transformer is almost invariably star/star connected, since both HV and LV windings must provide a neutral for connection to earth.

Until recently, such a transformer would automatically have been provided with a delta-connected tertiary for the elimination of third harmonic. However, as auxiliary systems and the transformers feeding them become larger, fault levels become greater, and at the ti me of designing the auxiliary system for Littlebrook D power station it became clear that the use of a 132/11 kV 60 MVA station transformer with a deltaconnected tertiary would create problems in the event of single-phase-to-earth faults on the 11 kV system.

Such a transformer has an inherently low zero-sequence impedance and it is difficult for the designer to increase this whilst maintaining the positive-sequence impedance low enough to meet the required regulation performance. The solution appeared to be to omit the tertiary, but then concern arose as to whether this

.,% ould result in the zero-sequence impedance becoming Huh that single-phase-to-earth faults on the

„ Te m v.[ou1.1 not pass sufficient current to operate he protectior Consultations with transformer manufacturers suggested that this would not be so, since he transformo- tank would behave as a very looselycoupled tertiary winding. This was confirmed by the works tests on the first transformer which showed that the zero-sequence impedance, measured on the t. V winding, was about six times the positive-sequence

attic and was low enough to permit satisfactory operation of the protection.

Although works testing showed that the actual value of zero-sequence impedance obtained by omitting the tertiary can be low enough to meet the auxiliary system protection requirements, it is necessary to ensure that the absence of a tertiary will not give rise to excessive third-harmonic currents circulating in the system neutral. Such currents flow whenever the system has more than one neutral, as in the example shown in Fig 3.61 where an auxiliary gas turbine generator with its neutral earthed is operated in parallel with the station transformer supply, thus setting up a complete loop for circulating currents. (The impedance of this loop to third-harmonic currents can be increased by connecting a third-harmonic suppressor in series with the gas turbine earth connection, see Section 2.5.6 • of this chapter.) Such a situation can exist at Littlebrook D and it was shown from site tests and calculations that the omission of the tertiary resulted in a three to four-fold increase in the third-harmonic current

gas turbine neutral compared with systems which have a normal delta-connected tertiary on the station transformer. With an absolute value of no more than about t A in the transformer neutral, however, this was still considered to be acceptable. Without the gas

2,V SUB-STATION

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GAS TURBINE

GENERATOR

LIQUID

EARTHING

RESISTOR

Ikv STATION BOARD

EH_ 3.61 Connection of gas turbine neutral in parallel with station transformer neutral

turbine connected in parallel, the station transformer neutral carried a third-harmonic current of less than 0.3 A.

In order to ensure that protection problems are not encountered on future station transformers, it is now CEGB practice to specify that the zero-sequence impedance should fall within a band from 0.9 to 6 ti mes the positive-sequence value.

Reference has been made in Section 1.5.1 of this chapter to the use of an on-load tapchanger on the station transformer as a means of compensating for grid voltage variation and for regulation within the transformer itself. This has an important bearing on the design of the station transformer.

So that the 11 kV station board voltage remains at an adequate value under full-load conditions, the open-circuit ratio of the station transformer is selected to give a low voltage somewhat above nominal. A figure of 11.8 kV is typical.

Under normal operating conditions the grid system voltage may be permitted to rise to a level l0°'0 above nominal. On the 400 kV system this condition is deemed to persist for no longer than 15 minutes. For the 132 kV and 275 kV systems, the condition ma), exist continuously.

Should the station transformer HV volts rise above nominal, the operator may tap-up on the tapchanger, i.e., increase the number of turns in the HV winding. If the •HV voltage were to fall, he would operate the tapchanger in the opposite direction, which would reduce the HV turns: both these operations maintain the flux density constant.

The operator can also use the tapchanger to boost the LV system voltage, either tocompensate for regulation or because a safe margin is required, say, to start an electric boiler feed pump. The tapchanger would increase the volts/turn and this would thus increase the flux density.

The station transformer will probably have been provided with a tapping range of ± 10% to match the possible supply voltage variation. On the limit, it is possible for a voltage which is 10 07o high to be applied to the — 10% tapping. This is an oven, oltage factor of 22% and would result in an increase in flux density of this amount. To avoid saturation, it is desirable that the operating flux density should never exceed about 1.9 T; this results in a specified flux density of 1.55 T at nominal volts for all station transformers, a value considerably lower than that specified for other transformers, e.g., the generator transformer.

2.3 Unit transformers

2.3.1 Unit transformer characteristics

The unit transformer is teed-off from the main connections of the generator to the generator transformer It is energised only when the generator is in service

and supplies loads which are essential to the operation of the unit.

The design criteria to be met by the unit transformer are as follows:

•The H V voltage is 23.5 kV.

•The LV voltage is invariably 11 kV nominal.

•I mpedance must be such as to enable it to be paralleled with the station transformer at 11 kV

without exceeding the permissible fault level — usually about 15 07a.

•Since the HV voltage is maintained within +5 0/o of nominal by the action of the generator AVR, on-load tapchanging is not needed.

•Operating load-factor is high, so that load losses and no-load losses will both be capitalised as the same rate. (Except in some nuclear stations, where two fully-rated unit transformers are provided per unit for system security purposes.)

•Paralleling of unit and station transformers during changeover of station and unit supplies can result in a large circulating current between station and unit switchboards (Fig 3.62). This adds to the unit transformer load current, and subtracts from that of the station transformer. The unit transformer must therefore be capable of withstanding the resultant short-time overload.

2.3.2 General design features

The above design criteria are met by a delta/star transformer having an open-circuit voltage ratio of 23.5/ 11.8 kV, equivalent to 23.5/11 kV at full-load 0.8 power factor, with off-circuit taps on the HV winding of +7.5 07o in six steps of 2.5°70. For the reasons explained in Section 1.5.6 of this chapter, these are varied nowadays by means of links under the oil rather than using an off-circuit switch which was the previous practice.

The changeover of unit and station supplies normally only requires that these transformers be paralleled for a few seconds. This is long enough for the operator to be sure that one circuit-breaker has closed before the other is opened. During this time, however, a circulating current can flow which is dependent on the combined phase shift through the unit, generator and station transformers, plus any phase shift through interbus transformers, if generator and station transformers are not connected to the same section of the grid system. This can result in the unit transformer seeing a current equivalent to up to 21/2 full-load. Should the operator take longer than expected to carry out this switching, the unit transformer windings will rapidly overheat. Such a delay is regarded as a fault occurrence, which will only take place fairly infrequently. It is considered that parallel operation for a time of two minutes is more likely to occur than a short-circuit of the transformer and so the limiting