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

For stations with generator voltage switchgear, some faults in the above groups may allow the unit electrical system to remain connected to the grid system.

Steam raising plant to generating plant intertrips are simple to design for steam generation/turbine units, as a trip of the steam raising plant will trip the aenerator and vice versa. For stations where common steam raising plant feeds more than one generating

unit, logic -lust be introduced to detect that only one Lienerating nit has tripped if the design allows the steam raising plant to ramp down to 50% load. This

applies to th.: present design of PWR.

4.3 The effects of loss of grid supplies

Loss of grid supplies is a generic term which covers events from the loss of a single generator connection, to the total collapse of the local grid network. Grid disturbances, which cause the voltage and/or frequency to go outside their operating limits, must also be considered in this category. The following sections examine the various mechanisms which lead to grid disconnections.

A power station connected to the National Grid will experience all the voltage and frequency transients which occur on the surrounding grid system from time to time. From a system operation point of view, it is desirable to keep generation connected throughout these disturbances to support the system and its stability. However, the design and operation of generating plant will be specified to limits of voltage and Frequency in the station technical particulars. These li mits (as detailed in Section 5.1.(d) of this chapter) are those which are expected during normal operation. For conditions which may be considered abnormal, which will probably be outside the specified limits, the power station designer must consider deliberate disconnection of the station from the abnormal grid. This action is necessary to avoid possible overstressing of the electrical auxiliaries system or subjecting the mechanical plant to conditions outside its specified limits. This is of particular importance in nuclear plant which is nuclear safety-related, but is also of importance from an economic standpoint on conventional plant as repairs and outage time are very costly.

In present nuclear stations, specific voltage/frequency detecting equipment is installed normally at the 11 kV voltage level, but may also interface with the essential system which may have its own specific dedicated monitoring equipment. Should the power station electrical auxiliaries experience conditions outside the preset limits for more than the specified time, automatic disconnection is carried out, the station is shut down and power is supplied from the essential supplies generator sets.

Earlier CEGB power stations have their electrical protection arrangements designed such that faults which open the generator transformer HV circuit-breaker will

also trip the generating unit. Designs for AGR stations have specified that a 'run through' capability be provided. This means that on opening the generator transformer HV circuit-breaker only, thus disconnecting the generator from the grid, the generating unit will ramp down to house load. If the grid becomes available after a short time, the generator can then be re-synchronised without having to suffer the lengthy down times necessary to run up a machine after a hot or cold shutdown. This is of particular benefit since restarting is always a lengthy process due to Xenon poisoning in the reactor. In practice this operating regime has been difficult to achieve, mainly due to li mitations in the very rapid control of mechanical plant and/or the reactor at low power levels. Intended 'run through' periods of approximately 10 minutes have been aimed at with subsequent shutdown should grid supplies not be available after that time.

To achieve this feature, it is necessary to arrange the electrical protection such that faults which need only trip the generator transformer HV circuit-breaker to isolate the fault, will not trip the unit or its connection to the electrical auxiliaries system.

Certain grid disturbances local to power station sites in relatively weak grid areas, could cause the generators connected at the time of the fault to go outside their stability margin. This is because during the clearance ti me of the fault, the system voltage is depressed and no power export is possible. The excess energy is stored in the machine as an increase in rotor angle and may, dependent on the clearance time of the fault, cause the rotor angle to increase beyond its stability limit, resulting in pole slipping. Although the plant can be protected against this condition, the effect on the grid system from the consequent loss of generation is detrimental to its continued stability.

Therefore consideration must be given to taking certain measures which will improve the transient stability of the generators in areas of weak grid connections. Several methods have been considered for adoption and basically fall into two groups:

(a)Those which may be implemented on the turbinegenerator unit.

(b)Those which may be implemented on the grid system.

Methods in group (a) include fast-acting AVRs and possibly faster closure of the turbine stop valves, although this latter technique has not been proven on UK plant.

Methods in group (b) include the addition of switched shunt reactors at 400 kV, automatic VAr compensation and static compensation.

A new technique being investigated by the CEGB, is the addition of braking resistors connected at generator voltage. This is a method in group (a) where the resistors would be connected in the power station.

In this method, a large resistive load (approximately 300 MW) is connected across the generator .terminals for a very short period of time immediately following the fault clearance and hence voltage recovery. This gives the effect of absorbing the excess kinetic energy stored in the venerator rotor, avoiding the power swings which would otherwise occur. There is a need to identify the point at which the braking resistor is to be applied and the length of application. It is also necessary to use a switching device which is fast enough to be compatible with the detection method.

The control scheme envisaged is based on an energy measurement system which constantly monitors the generator, and calculates in 10 ms time periods the energy and compares this against a preset value. The ti me at which the braking resistor is required and the length of application is calculated and the resistor switch is signalled to close. Typically a fault duration time of 85 ms would cause a braking resistor application in the region of 100 to 150 ms.

A prototype has been designed and constructed for trial at Pembroke Power Station at a relatively weakly connected part of the grid. Preliminary indications are that this method will be more effective than shunt reactors for improving the generator's response to transient instability conditions.

The loss of grid connection normally means the loss of electrical supplies to the unit (and possibly station) auxiliaries. Certain auxiliaries are required to continue in operation after unit trip to achieve a safe shut down state. For conventional power stations, the post-trip requirements are less onerous than for nuclear power stations.

For conventional stations, battery-backed supplies or small diesel generators may suffice. The duty will include maintaining supplies to drives such as generator seal oil pumps or barring gear motors.

Nuclear plant however, because of the decay heat due to fission products, requires more and larger drives to be maintained for longer periods of time. The posttrip requirements for most nuclear plant last for days rather than hours, and hence there is a need for a much more robust essential electrical system. As posttrip cooling is also claimed as part of the nuclear safety case, redundant plant is provided.

A more detailed description of the post-trip requirements for AGRs and PWRs is included in Sections 3.3.3 and 3.3.4 of this chapter respectively.

Previous nuclear stations based their safety cases on the ability to provide post-trip cooling without a grid connection being available. The various fault sequences were examined on a deterministic basis, and the case was made by demonstrating that there was sufficient redundant plant available to achieve the necessary safe shutdown state.

The later AGRs and the PWR designs were examined using probabilistic analysis techniques using assigned values of component and system reliability to analyse various fault sequences against an overall target figure.

In the case of the PWR, a predominant contributor to the overall frequency of degraded core was the fault group 'loss of all II kV'. The value of frequency for this fault group was found to be dominated by the frequency of loss of off-site power (LOSP), and detailed analyses were undertaken to determine the figure for LOSP frequency for the selected sites.

The PWR safety case is made on the basis of, interalia, the estimated value of LOSP frequency. The frequency of LOSP is therefore a major consideration in assessing the reliability requirements for the on-site generation provided to meet the essential electrical system duties. The reliability assessment must consider the starting and continued running capabilities of the auxiliary generation to cater for the LOSP ti me bands such as those outlined in Section 2.4 of this chapter.

4.4 Station plant outages and faults

There are two types of outage which have to be considered in the design of the power station auxiliaries system. These are:

•Planned outage The CEGB has a policy of regular maintenance for all power station plant. Although regular maintenance is normally carried out when the unit is shut down, there is often a requirement to maintain a supply to an associated piece of plant. This is particularly so when considering nuclear stations. Also some equipment may require maintenance more regularly than the unit outage period. To reflect these needs the design will normally incorporate sufficient diverse and redundant plant to a level necessary to maintain supplies to essential plant.

•Forced outage Despite the regular maintenance policy, plant will occasionally become unavailable for example due to a fault. The repair of faulted equipment is known as 'breakdown' or 'urgent' maintenance. The defence against this occurrence, where it would compromise nuclear or plant safety, is to design the system with sufficient redundant items and supply routes to maintain essential supplies and enable equipment to continue operating. This is especially important for essential nuclear plant.

The design principles to achieve the necessary level of security require plant systems to be provided as main and standby, separated or segregated from each other. Similarly, the electrical supply routes must be run separately or segregated, with the electrical supply, as far as practical, derived from independent sources.

For the nuclear station essential systems, the level of redundancy required is much greater than for fossilfired plant. The present approach is to segregate plant, supply routes and sources, into functionally independ-

ent groups or 'trains', each train having its own essential system generators. These are normally diesel driven generators connected at 3.3 kV, diesels being chosen for their high starting and operational reliability. For the PWR design, for example, a four train system has been chosen. Each train has a separation oroup allocated to it and all associated plant is physically separated from other train equipment.

Auxilia y generator sets may be installed at a power station for he reasons given in Section 3.2.4 of this

chapter.

To meet the requirements for auxiliaries frequency support, 'peak lopping' and 'black start', auxiliary generators are fitted to the unit and/or station switchboards at 11 kV. Due to the ratings required to start up modern plant, they are likely to be gas-turbine

generators.

For the essential duty, due to the smaller load demands and more onerous response time and reliability required, diesel generators are nowadays used at 3.3 kV although gas-turbine generators have in the past been used to meet essential duties.

As mentioned in Section 3.2.3 of this chapter, the essential system for the Sizewell B PWR, for example, has been chosen on the basis of four functionally independent trains, with a diesel generator connected to a 3.3 kV board on each 'train'. Each train is segregated from the others by fire barriers, and also all the equipment and cabling is segregated similarly.

5 System choice

5.1 Operational requirements

All power stations operated by the CEGB have their operational requirements set down by the CEGB's System Planning Department in the Station Development Particulars (SDPs).

The choice of electrical system will be influenced by these requirements, the major aspects of which are discussed below:

(a)Most nuclear fuelled plant is operated in a 'base load' regime especially as the output cost/kW from nuclear plant is cheaper than most fossil-fuelled plant. Coal-fired plant is, however, more adaptable to following the load demand curve. Clearly the electrical system must facilitate the operational flexibility where this is required. In nuclear power plant the overriding consideration is one of nuclear safety, and this is always uppermost in the designer's mind. The system chosen for nuclear plant must have an inherent ability to be configured in the most appropriate form for post-trip cooling, bearing in mind the alternative supply choices available.

(b)The electrical system is required by the SDPs to be designed such that a single fault will not cause

the loss of more than one generating unit. This reflects the need to limit the generation loss to the system due to single faults. The connections to the grid site must also be examined to ensure that a single System or substation fault will not cause more generation loss than the System can tolerate. This is of particular concern in situations where more than one station is connected to a common substation.

(c)Power plant designed and installed in the early 1960s assumed that grid loss could be tolerated

and that the transmission system would not totally collapse. Subsequent events showed that a condition could occur which caused 'cascade tripping', i.e., power stations being tripped in an attempt to supply loads in excess of rating. This led to power plant being specified which could be started up in the absence of external grid supplies.

For the 500 MW units, a twin Avon (25 -28 :v1W) gas-turbine generating set was used, but this was superseded at the later stations having 660 MW units by twin Olympus (35 MW) sets because of the need for a larger rating. The generator output voltage in all cases was nominally 11 kV and the gas turbines were connected to the II kV unit boards.

Gas-turbine generators were installed for duties summarised as follows:

• Black station starting The gas turbine is run - up and closed onto a dead busbar. Synchronising is only required for regular testing in parallel with the grid derived supplies. Gas turbines would normally be connected to the unit board.

As the gas-turbine generators have to be paralleled with the grid, automatic synchronising is provided. GTs would normally be connected to the unit board when the associated main unit is generating or via the unit/

station board interconnector to the station transformer when the main unit is shutdown,

• Frequency support The gas-turbine generator responds to falling frequency, starts, and is closed onto the busbar; this is specified to occur at frequencies down to 40 Hz and auto synchronising is required.

• Supplies to essential equipment Supplies to essential drives such as generator seal oil, barring gear and, if a nuclear plant, electrical supplies to the post-trip cooling equipment.

The choice of rating, the number of gas turbines and their connection to the auxiliaries system, are all influenced by the duty required of them. Consideration must be given in the duty definition to the requirements for manual and/or automatic start, auto and/or manual synchronising, and for the inclusion of centralised control.

The first AGR nuclear stations were fitted with single Olympus gas turbines at 17.5 MW rating but these were for nuclear safety needs primarily, and were not intended for black start purposes, although some peak lopping duties were performed.

(d)The plant must be designed to meet the voltage and frequency limits set by the system. Typically these are as follows:

•All electrical plant must be capable of maintaining full CMR output within the range 49.5- 51 H. From 49.5 to 47 Hz the output may be prorata with frequency, but operation below 48 Hz will not be for longer than 15 minutes.

•Frequency excursions between 51-52.5 Hz may be experienced, but these will only be for short periods.

•The HV system voltage to which the power station is connected is nominally 400 kV or 275 kV, with typical limits of:

400 kV, +5%

275 kV, +10%

The electrical auxiliaries system must be designed to recognise these variations, as well as taking into account the drop in voltage throughout the system due to varying load and running conditions. Most modern conventional power plants have three main nominal voltage levels viz, ii kV, 3.3 kV and 415 V. The design limits of these voltage levels are typically from +6% to - 10% with -20% under motor starting conditions. The voltage at all nominal levels is maintained by means of optimising the transformer tap positions, such that the 415 V drive most remote from the primary (11 kV) busbar is subjected to a voltage within the tolerance under the worst condition, e.g., when starting. A check of the voltage profile under light load conditions is also made to ensure that the system is not overstressed.

The design stage voltage profile is verified by system studies which model the system using interactive computer programs.

These studies will of course need updating at a later date when all the manufacturers' data is known. This is described more fully in Chapter 2.

5.2 Reliability of main and standby plant

The design of the electrical system should, in general, reflect the requirements of the mechanical plant and should not reduce its reliability. Where important mechanical systems are provided with redundancy, the electrical supplies should also be redundant. Therefore main and standby plant should be supplied electrically from independent sources, via segregated supply routes.

For nuclear power stations, the mechanical and electrical plant may well require segregation, and will ultimately be segregated into independent functional 'trains'. This approach has proved to be the most robust system of providing defence against the whole range of credible faults, verified by probalistic analysis techniques.

The use of diverse equipment in independent functional trains also benefits by reducing the impact of common mode and common cause failures. These techniques can be employed to provide the level of reliability required for the systems which are associated with nuclear plant.

The reliability of a system will be analysed by the use of probalistic analysis techniques. To obtain a meaningful answer, the component reliability must be assessed. This is not always easy from a historical point of view, when components may have been in use only for a few years. However, by using equipment which has been rigorously and systematically tested, a certain degree of confidence may be obtained from the attributed component failure rate. Using a degree of pessimism in the calculations also expands the confidence factor of the figures used. Component failure rates are considered not only for normal conditions but also for abnormal conditions both natural and following major plant disruptions. This includes seismic events and extremes of pressure, temperature and radiation levels, and also missile impact. equipment is classified into items which are required to withstand seismic and environmental conditions and those which are not. Again verification is achieved by subjective testing.

The choice of system will depend on the reliability required of it and the availability of suitable components.

The use of proven equipment, which has demonstrated a satisfactory performance under varying conditions, will also support the predicted reliability of the system. New designs of equipment should be avoided in essential systems, unless they have been developed and tested to demonstrate standards of technical requirement at least as high as those claimed in the system design.

The reliability of electrical systems is also enhanced by ensuring that designs follow the design principles as outlined in the introduction to Section 3 of this chapter.

5.3 Economics

The choice of electrical system for a particular power station project will be influenced by several economic factors, the main aspects of which are discussed below.

Capital cost

The initial capital cost of an electrical scheme can be estimated from a cost analysis of the various corn-

ponents proposed. This can be achieved using data from many sources, for example:

•Contract prices of similar equipment on other (preferably recent) projects.

•Budget prices from possible suppliers or manufacturers.

•Standar:I cost estimating databases.

To enable a true comparitive estimate to be made, all prices aad costs must be related to a common price basis date. Any adjustment must be made using standard factors. Where designs are not finalised, a judgement must be made and an estimated cost attributed to it in the form of provisional sums, to allow for any variation from the base design.

The CEGB employs a standard capital cost breakdown method for estimating new projects, where costs are allocated to particular coded plant areas. These costs are reviewed on a regular basis (usually annually) and updated as and when more firm information becomes available, e.g., tender prices or contract sums. In this way, close cost control can be applied to ensure that the project remains within the budget.

In the early stages of a project, when designs are still subject to change, it is difficult to finalise the final electrical system due to the lack of confirmed information regarding the mechanical plant it is required to supply. However, by use of the estimating techniques mentioned above, it is possible to compare one proposed scheme with another for a particular duty so that the most cost effective scheme may be chosen.

Transformer losses

Transformers associated with modern power stations are of ratings up to 60 MVA for unit and station transformers, and up to 1150 MVA for 900 MW unit generator transformers. Although designs are available which minimise the losses, they are still significant when taken over the life of the station. It is therefore present practice to include an estimate of the capitalised losses over the station life in the station cost estimates, Due regard to this element must be exercised in the choice of electrical system.

Consequential costs (connection to the National Grid)

To connect the power station into the National Grid will require extra circuits to be used or provided at the transmission substation adjacent to the proposed site. In general, most substations have been in existence for some time and it is rarely a simple job to connect new generating plant to the existing system. The cost of the generation circuits, associated circuit-breakers, isolators, busbars and civil costs are attributed to the power station capital estimates. The costs for the remaining EHV equipment are attributed to the transmission account but, nevertheless, alternative config-

urations will be examined to arrive at the most cost effective scheme. Some of the options which are likely to require examination are as follows:

It is a policy to connect all modern new generating plant to the 400 kV system. The facilities available at the substation will determine whether a new 400 kV substation would be required or the existing equipment extended. It is also a policy to construct new 400 kV substations with metalclad gas-insulated (SF6) equipment, and if at coastal or polluted sites to enclose them within a building.

station transformers may be connected at 132 kV, 275 kV or 400 kV. The choice depends on several factors as discussed in Section 3 of this chapter. The most economic option will normally be a 132 kV connection. The electrical load on the station transformers imposed by modern power plant is considerable, it may therefore be necessary to uprate the 132 kV substation by the addition of an extra supergrid (400/132 kV) transformer to support the capacity required. This reinforcement of the 132 kV system, if required only to meet the new power station load, may make this scheme economically less attractive. Also the position of the 132 kV substation may require very long cable connections, again adversely affecting the scheme economics.

Cost analyses showing these considerations will demonstrate which is the most economic proposal, but the final decision will be based on a combination of economic, technical and operational considerations.

Development

Whilst the CEGB policy is to use proven and tested plant, development work is often required to meet a need which has hitherto not been identified, The cost of this development work may be borne by the project and in that case a capital sum is included in the project estimates. The choice of system design may be influenced by the need to develop a particular piece of plant rather than use an existing alternative. In this case, a justification would have to be made to demonstrate the technical superiority compared with the cost of the development work.

Sometimes development work is required because the previous equipment is no longer available, or is no longer manufactured, and there is no suitable alternative on the market. This situation often is not attributable to a particular project and would be funded from a general development budget.

Decommissioning

At the end of a power station's life, it will require decommissioning or dismantling and the site prepared for other usage.

For fossil-fired plant, this is a fairly straightforward exercise. For nuclear stations, however, the job is much more complex and protracted involving removal of fuel from the reactor, placing it into the cooling pond and finally removing it from site for processing. The costs of this work must recognise the need for an integrity and security of supply during fuel removal, as well as additional monitoring of the reactor structures whilst removing contaminated material after fuel removal. These costs will also be included in the station's capital estimates.

5.4 Plant limitations

The electrical auxiliaries system must be designed to meet the needs of the mechanical plant, i.e., the starting, operational and protection needs of all the electrically-driven items. The problem the electrical system designer is faced with is twofold, firstly, the electrical system can only be finalised when all the parameters of the mechanical plant are known, and secondly, electrical plant itself has technical limitations which must be borne in mind. The following sections describe some of the major limitations which confront the system designer on modern power station plant. it is assumed that the major mechanical drives are known, at least in principle, and that a fair estimate of their load demand is available.

5.4.1 Switchgear current rating

As mentioned in Section 3 of this chapter, the primary auxiliaries system voltage is largely determined by the largest electrical drive, normally the electric boiler feed pump. In the past, steam turbine feed pumps have been used, but the new coal-fired designs proposed for the 1990s are specifying full duty electrically-driven feed pumps in a 3 x 50% combination without turbinedriven pumps. For a subcritical pressure design of boiler the rating of each 50% pump motor is 13.5 MW.

The decision to fit flue gas desulphurisation (FGD) on all new coal-fired plant and to retrofit it to some existing stations has meant a considerable increase in unit and station electrical load.

The CEGB approved ranges of II kV switchgear have a maximum current rating of 3150 A. This leads to a maximum 11 kV transformer output of approximately 60 MVA. For station and unit loads in excess of this, consideration must be given to using more than one 2-winding transformer or, alternatively, the use of 3-winding transformers, i.e., transformers having two secondary windings. This will increase the number of switchboards at the primary voltage level, leading to more complex start-up/shutdown arrangements. An example of a calculation for maximum unit or station transformer rating is shown below.

BS171 defines the method of rating calculation for transformers as:

Transformer rating = J3 x 11 kV circuit-breaker current rating x open-circuit voltage of the transformer secondary winding.

Assuming a typical open-circuit secondary winding voltage of 11.5 kV and 3150 A, 11 kV circuit-breaker rating:

10 - 6

= 62.57 MVA

It is obvious that this rating is notional as the transformer cannot provide open-circuit voltage when on load. Hence the actual transformer capability is closer to the value obtained by using the transformer nominal secondary winding rating, i.e.,

Rating = -13 x 3150 x 11 x 10 3 x

106

=60 MVA

Similar constraints are imposed at other voltage levels by the limit of switchgear current rating, restricting the maximum transformer sizes accommodated by the system.

5.4.2 Switchgear short-circuit rating

Normal start-up arrangements are such that the unit start-up supplies are derived from the station transformer and these are transferred to the unit transformer after the unit has been synchronised to the grid and part loaded. This requires paralleling of unit and station sources at 11 kV. Also, at lower voltage levels, paralleling may be required to changeover from one supply source to another should supplies need to be maintained to the connected plant. Paralleling at lower voltage levels, however, is not normally part of start-up procedures.

The fault level at a switchboard is predominantly limited by the impedance of the supply transformer, although connecting cables also add to the source i mpedance, but not significantly. Whilst fed from a single source, the fault levels normally experienced are well within the rating of the switchgear. This however is not always the case when two sources are paralleled, but by adjusting the transformer impedances appropriately, the designer is normally able to arrange for parallel operation, especially at 11 kV. There are however other limiting factors, notably, the starting of large induction motors direct-on-line and the required system voltage profile. In extreme cases consideration must be given to the addition of inductors between switchboards, when parallel operation is required, to limit the prospective fault levels. These inductors may have to be designed such that they can be shorted out to avoid voltage drop problems under standby operation.

For situations requiring additional generation such as for the emergency provision of essential power (by either gas-turbine generators or diesel generators), fault level problems may also occur. If the additional power g enerator is connected in parallel with the grid or another source of supply, care must be taken in the design of the electrical system to ensure that switchgear fault levels are not exceeded. Such paralleling may be

required, fcr example, under peak lopping, frequency support, or testing conditions. An example of fault

level calculations is shown in Section 5.4.4 of this chapter.

5.4.3 Large electric motors

As mentioned in Section 5.4.1 of this chapter, the new coal-fired designs will have 13.5 MW boiler feed pumps. Motors of this size are difficult to start direct- on-line, due to the starting current experienced causing unacceptable voltage drops in the lower voltage systems. The designer is then faced with the conflict that the transformer impedances must be high enough to allow parallel operation while limiting prospective fault levels, but low enough to start large electric motors without serious voltage regulation problems.

If no satisfactory compromise can be established, other solutions must be considered. The most likely avenue is to employ alternative starting methods for the large motors, or to achieve transfer of supplies without paralleling.

Fast transfer

In this method the unit and station supplies are transferred, but are not paralleled. The interruption time is sufficiently small that the motors do not slow down enough to be affected by re-energisation a few milliseconds after supply interruption. The use of presently approved air break circuit-breakers does not, however, give any confidence that consistent successful changeovers will be achieved with any degree of reliability. This is due to the relatively slow and inconsistent operating times of air break circuit-breakers. The use of vacuum circuit-breakers having much shorter operating times will overcome this difficulty and are now being introduced into power stations.

Assisted motor starting

With the introduction of thyristor-based equipment, the speed control of motors has become very precise and many manufacturers offer standard systems. With motors of the size envisaged for the new coal-fired plant, static conversion equipment may require deelopment, but there do not seem to be any technical li mitations and this course would appear to be the most promising method of current-control starting of large motors. The additional space required for the static conversion equipment must be taken into account

when laying out the plant and the additional civil costs borne in mind.

Another benefit of assisted starting of large motors is that the fault level contribution under 'making' conditions should be limited and may be negligible. If the design is near the switchgear rating limit, static conversion equipment will assist in reducing the fault level. A further benefit is the possibility of variable speed which may be of use for plant operation.

Generator main connections

The largest generating unit connected to the grid system in the UK is 660 MW. The new coal-fired plant will introduce larger units of about 900 MW rating.

The present 660 MW generator voltage is 215 kV, with a full load current of 19 100 amperes. The proposal for the 900 MW design is to raise the generator voltage to 26 kV. The temperature rise allowed on the phase isolated busbars will limit the current rating on the present designs which, although they are rated at voltages in excess of 23.5 kV (voltage rating being 33 kV), are at the practical limit of current capacity with natural air cooling. The use of forced cooling methods will need to be considered, with sufficient redundancy to attain the necessary reliability.

It is not uncommon to have to design the layout and fixing details of the generator end of the main connections to accommodate the particular wishes of the generator manufacturer. It is outside the scope of this section to discuss this in detail, but if the machine terminals do not have sufficient clearance to accommodate air-cooled phase isolated connections consideration must be given to the use of water cooled connections at least in part (see Chapter 4 on generator main connections).

All these considerations have effects on the surrounding plant, e.g., the generator transformer will need to be developed to a suitably increased rating. This will affect the registered design concept which will need review (see Chapter 3 on generator transformers).

5.4.4 System performance calculations

In order to assess an electrical system's performance fully, studies must be carried out using the interactive computer analysis programs described in Chapter 2 of this volume. These require a considerable amount of data to be gathered, which may be actual, typical or estimated values, but may not be available in the early stages of the electrical system design. The designer must check his provisional design by traditional hand calculations. A typical system is shown on Fig 1.19 and the typical calculations used to check the design are shown below.

The unit system and station system may be considered as two separate systems for the purposes of fault level calculations.

Unit system

The unit system may be represented by a simple i mpedance diagram as shown in Fig 1.20, with the generator and grid being considered as two sources.

This equates to the impedance diagram shown in Fig 1.21.

The values of impedance are calculated as follows using a 100 MVA base:

SOURCE

GRID

Zgricl

Zgrid Assuming the maximum fault infeed is equivalent to the switch gear rating, viz 35 000 MVA, then the p.u. impedance on a 1000 MVA base is

7gen Generator subtransient reactance is assumed to be 0.20 p.u. on a rating of 660 MW, therefore:

I mpedance on a 100 MVA base =

ing a 5 07o negative tolerance)

Zgent

FIG. 1.20 Impedance diagram for unit system

Zgnd

Zgen

Zgenl

Zut

FAULT

FIG. 1.21 Equivalent impedance diagram for Fig 1.20

Zgent Assuming the generator transformer to have an impedance of 16% on a rating of 800 MVA:

(where a 10% negative tolerance is assumed)

therefore Zgent = 0.018 p.u.

Zut Assuming a unit transformer impedance of 17.5% on a rating of 60 MVA:

where a 10% negative tolerance is assumed.

therefore Zut = 0.263 p.u.

Substituting these values into the impedance diagram

shown in Fig 1.22. This simplifies to the impedance diagram shown in Fig 1.23. The equivalent impedance

to the parallel branch is:

0.0245 x 0.0209

(0.0245 + 0.0209)

= 0.0092 p.u.

0 0029

0.0245

0 018

FAULT

Impedances in p u on 100 MVA Base

FIG. 1.22 Typical impedance values for a 900 MW unii

SOURCE

GRID

FIG, 1.23 Simplified impedance diagram for Fig 1.22

Equivalent source impedance is (0.0092 + 0.263) p.u. = 0.272 p.u.

The equivalent fault contribution for a fault on the unit board 11 kV where the circuit-breaker interrupts the fault is:

100 MVA

0.272

The 11 kV unit system fault contribution = 367 MVA

(1.1)

Additionally, if a circuit-breaker closes on to a fault, then the contribution from the motors and 3.3 kV system backfeed must be taken into account. This contribution is calculated as below.

The contributing MVA of a motor for hand calculations is assumed to be the ratio of the starting MVA to the MW rating and hence the value is obtained from the motor rating and the multiplication factor specified for motor starting in BS4999. For the purposes of the following calculation, a figure of 5.5-times for motors up to 10 MW and 5-times for motors greater than 10 MW is assumed.

Typical figures for a 660 MW coal-fired unit would be:

The 11 kV motor contribution is therefore calculated by considering the number of motors connected at the ti me of the fault. For this example it is assumed that the following drives are connected

2 ID fans + 2 FD fans + CW pump + BFP + PA fan (36.3 + 25.4 + 20.6 + 49.5 + 5.5) = 137.3 MVA (1.2)

In addition, the contribution back fed from the 3.3 kV Unit Auxiliary Boards must be taken into account.

Assuming that a typical 3.3 kV unit load is 6 MW fed through a 12.5 MVA 12%, 11/3.3 kV transformer:

3.3 kV starting MVA -= 6 x 5.5 (assuming a starting MVA/MW ratio of 5.5)

= 33 MVA

100

on a 100 MVA base, equivalent impedance =

33

- 3.03 p.u.

12.5 MVA transformer impedance on 100 MVA base

= 0.96 p.u.

Therefore, total 3.3 kV to 11 kV impedance

=3.03 + 0.96 p.u.

=3.99 p.u.

3.3 kV motor backfeed contribution = 25 MVA

(1.3)

The resultant fault level at the 11 kV unit board being considered is 529 MVA. This value is a symmetrical making duty that the switchgear must accommodate. It should be understood that the switchgear is rated on a making first loop current peak which assumes a value of 121 kA. The equivalent RMS symmetrical figure (expressed in MVA for convenience) is calculated as follows:

121

121 kA peak is equivalent to - kA RMS, but

to calculate the RMS value of the absolute peak of current at the instant of initiating a short-circuit, a further factor of 0.9 is applied.

This equates to an equivalent MVA value of

x 11 x 10 3 x 47.54 x 10 3 = 905 MVA

A value of 900 MVA is chosen for calculation purposes as a notional MVA value. The figure of initial peak current values are unlikely to be seen in practice due to the relatively slow operation of the switchgear and the fact that the fault current will decay during the switch operating period. Also the voltage is depressed at the time of the fault and the notional value is unlikely to be achieved.

Station transformer system

The station transformer fault contribution is calculated in a similar manner to the unit system. The station system may be represented by the simple impedance diagram shown in Fig 1.24.

Zgrid may be assumed to be the same value as used for the unit calculation, viz 0.0029 p.u. This assumes that the station transformer is connected at 400 kV. However, Zgrid for the 132 kV system when combined with the station transformer impedance will result in