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

1Introduction

2Basic terms and synchronising criteria

2.1Definitions

2.2Switching operations

2.3Generator synchronising

2.4Synchronising errors

2.4.1Voltage error

2.4.2Phase error

2.4.3Frequency error

2.5Faulty synchronising

3 Synchronising methods

3.1Manual synchronising

3.2Automatic synchronising

4 Synchronising facilities and controls

4.1Synchronising facilities

4.2Synchronising controls

4.2.1Steam turbine-generator

4.2.211 kV gas-turbine generators

4.2.33.3 kV and 11 kV distribution switchgear

4.2.43.3 kV diesel generators

5 Synchronising equipment

5.1Synchronising trolley

5.1.1Voltmeters

5.1.2Phase angle voltmeters

5.1.3Synchroscope

5.2Guard relay

5.3Check synchronising relay

5.3.1Phase measurement

5.3.2Slip frequency measurement

5.3.3 Voltage measurement

5.4 Automatic synchronising relay

5.4.1Steam turbine-generator synchronising

5.4.2Gas-turbine generator synchronising

5.4.3Diesel generator synchronising

6 Derivation of synchronising supplies

6.1Secondary supplies

6.2Selection of voltage transformer supplies

6.2.1Single voltage supply

6.2.2Incoming and running voltage

6.3Measurement accuracy

6.3.1Voltage transformers

6.3.2Interposing voltage transformers

6.3.3Burdens

6.3.4Lead resistance

6.4Synchronising supplies

6.4.1Steam turbine-generator

6.4.211 kV gas-turbine generators

6.4.33.3 kV and 11 kV distribution switchgear

6.4.43.3 kV diesel generators

7 Synchronising schemes

7.1Standard schemes

7.211 kV distribution circuit

7.3Steam turbine-generator — generator voltage

circuit-breaker

7.3.1Manual synchronising

7.3.2Automatic synchronising 7.4 Site commissioning tests

8 References

1 Introduction

Practically all of the generating capacity on the CEGB system is connected, through generator transformers, to the 400 kV or 275 kV transmission system. There are other sources of generation, such as II kV gas-turbine generators used to meet peak demand or emergency generation and some diesel generators generating at 3.3 kV, but these amount to a very small total capacity.

These synchronous generators operate in parallel, the total load dispatched being equal to the sum of consumer demand and system losses. The real power is shared in proportion to their driving power and the reactive power in proportion to their excitation. Consumer demand is constantly changing, being characterised by the cyclic daily variation between night ti me and daytime load, with relatively short periods of rapidly changing load at times of peak demand.

Under these conditions, the nominal 50 Hz system frequency is controlled partly by the automatic action of the prime-mover governors and partly by changes in total generated output instructed by system control centres and achieved by changing the governor set point. To avoid hunting, governors are designed to stabilise the frequency at a level corresponding to each new instructed output level. Any excess or shortfall in output therefore produces a corresponding increase or decrease in system frequency, a change in output being required to return the frequency to the datum level (50 Hz). By adjustment of the total number of megawatts sent out, the system frequency can be finely controlled and under normal conditions it is maintained within the range 49.8-50.2 Hz. Outside these limits, the CEGB has a statutory duty to maintain the frequency within the range 49,5-50.5 Hz.

2Basic terms and synchronising criteria

2.1Definitions

The basic terms used in this chapter are defined as

.01 PhaSOr relatiOnSh.0 at the •stant OelOre swItch contacts =se

FIG. 12.1 Phasor relationship between incoming and running supplies

paralleled successfully. For three-phase systems this requires that they have the same nominal voltage and Frequency, are balanced systems (i.e., phase to neutral voltages are of equal magnitude and 120 ° (eke) apart), and also have common phase rotation and phase relationship.

Voltage difference The difference in magnitude be- I\k,een the incoming voltage and the running voltage.

Voltage error The voltage difference at the instant before the switch main contacts close.

Phase displacement The electrical angle between the incoming voltage and the running voltage. Alternatively this is termed phase angle, however, both are usually abbreviated to phase. When zero this is termed phase coincidence.

Phase error The phase displacement at the instant before the switch main contacts close,

Frequency difference The difference in magnitude between the incoming frequency and the running frequency. When the frequency difference is small, this is termed the slip frequency and is usually abbreviated to slip.

Example: If the incoming frequency (f t ) is 50.06 Hz and the running frequency (f r ) is 50,01 Hz, determine the slip frequency (f s ):

Fs = fi — Fr

50.06 50.01

0.05 Hz

Alternatively, slip frequency may be expressed as a percentage of the nominal system frequency, i.e.,

percentage slip frequency =

[slip frequency/system frequency] 100

In the above example, the percentage slip frequency [0.05/50] 100 = 0.13/4.

Slip frequency is also a measure of the rate-of-change of phase. Again using the example, the rate-of-change of phase 0.05 x 360 = 18 ° (elec)/s or, conversely, equals 20 s per slip cycle.

Switch closing time The overall closing impulse response time of the switch when measured from the initiation of the closing signal to the closure of the s witch main contacts.

This can be divided into two components; the time taken for the control circuit relays and closing coil to operate and the main contact mechanism travelling ti me.

The switch closing time depends on the switchgear type and consequently there is a fair variation in times. For a generator voltage circuit-breaker, the control cir-

cuit operating time is typically 60-80 ms and the main contact mechanism travelling time is 245-255 ms. Typical operating times for an interposing relay used for remote switching are 35-40 ms and for a closing contactor or solenoid coil 15-20 ms. This last time is normally included in the measured closing time for the switch itself. The closing time for a transmission voltage airblast circuit-breaker is typically 75-80 ms and for a switch disconnector 150-170 ins. For 3.3 kV and 11 kV air-break switchgear the closing times are normally somewhere in the range 150-350 ms. Vacuum and SF6 switchgear closing times at these voltages are around 50 ms,

To include all possibilities, the switch closing times for a steam turbine-generator circuit-breaker or switch disconnector at generator or transmission voltage is taken to be within the range 75-350 ms and for 3.3 kV and 11 kV air-break switchgear within the range 100450 ms. The actual value is obtained from site measurement. Under normal conditions, the consistency of closing is assumed to be within ±5 ms of the measured closing time. Changes in switch closing circuit DC auxiliary supply voltage, which may be between ± 10 07o, can cause a further variation in normal switch closing times.

Advance angle The angle in advance of phase coincidence at the instant when the switch closing impulse is generated. This compensates for the switch closing ti me.. Correct selection of the advance angle for a given slip frequency results in phase coincidence at the instant the switch main contacts close.

Example: A switch has a closing time (t e ) of 300 ms, determine the correct advance angle when the slip fre-

quency (f ) is 0.15 Hz. Expressed as rate-of-change of

5 0

phase f s 0.15 x 360 = 54 (elec)/s

Advance angle -= f s x t, = 54 x 0.3

= 16.2 ° (elec)

Figure 12.2 shows the relationship between advance angle and switch closing time for different slip frequencies.

FIG. 12.2 Relationship between advance angle and switch closing time

FULL LOAD, %

100 -

50-

FULL LOAD. %

SYSTEM

RUNNING

FREQUENCY

100

50

producing a small load and is used to control power output. Position (c) shows the governor set at full-load.

The rate-of-change of the governor set point if a continuous raise signal is applied.

Different governor rates may be applied depending on the operating mode, but for synchronising it establishes the maximum rate-of-change of slip frequency. Typically at synchronisation the governor rate of a steam turbine-generator is 0.05 Hz/s.

2.2 Switching operations

Having described the basic terms, the next step is to determine the switches in a power system that need synchronising facilities. This is done during the design of the electrical system by examination of the switching requirements during normal operation, breakdown or maintenance outages, or during and after an emergency. Synchronising facilities are needed at every switch that may be selected to parallel supplies. In a power station, this is at generator voltage circuit switches and at certain switches in the electrical auxiliaries system, such as `incomer"bus section' and 'interconnector' circuits, which can be regarded as distribution circuits. At switches where two supplies cannot be paralled for system design reasons (e.g., fault level), electrical or mechanical interlocks are provided to prevent incorrect operation.

In any power system, there are a number of fundamental types of switching operation. At switches fitted with synchronising facilities, these include the following:

(a)The circuits being connected are dead uncharged circuits. This is predominantly a testing requirement.

(b)The switch connects a live circuit to a dead uncharged circuit. The live supply may be either a system or a generator.

(c)The switch connects two parts of a system which are already synchronously connected via a parallel path. The two parts may differ in voltage and phase but the frequency is common.

(d)The switch connects two independent systems. The two systems may differ in voltage, phase and frequency.

(e) The switch connects a generator tb a system. The t wo supplies may differ in voltage, phase and frequency.

Although, strictly, in (a) and (b) there is no synchronising requirement, the synchronising instruments are still used (as described in Section 3.1 of this chapter), and therefore this switching operation is sometimes termed override synchronising.

There is no basic mismatch in (c), although there will be some inequality in voltage and displacement

in phase brought about by circuit loading and transformer differences, etc. The magnitude of the phase displacement to some extent depends on the length and complexity of the parallel path. In a power station, the differences are not usually significant and may be regarded as fixed; however, if the phase displacement between the voltages is changing, as is more likely to occur at a transmission station, this produces an apparent slip frequency. Voltage adjustment is not normally necessary.

The type of switching operation described in (d) i s usually associated with a system split, i.e., the system has become subdivided into two or possibly more parts as the result of a fault or major incident; this arises infrequently at transmission stations. It may then be necessary to adjust generating station(s) frequency and voltage, as appropriate, if the two system parts are outside prescribed limits.

A similar situation occurs at a power station when synchronising the emergency supply system to off-site supplies following the earlier loss or disconnection of the latter. Again, this operation is rare.

The switching operation described in (c) is usually termed 'check synchronising' (after the check synchronising relay described later in this chapter) and that in

(d) is termed 'system synchronising'. However, since the two forms of synchronising involve the system, both switching operations are regarded as system synchronising for the purposes of this chapter. Furthermore, in

(c) the two parts of the system are synchronously connected, termed synchronous system synchronising; whilst in (d) the two parts of the system are not of the same frequency, termed asynchronous system synchronising. With both switching operations power redistribution occurs on switching.

Similarly, for the purpose of this chapter, switching operation (e) is termed

Since as with (d) the two supplies are not of the same frequency, this is termed

chronising. Means of adjusting both voltage and frequency are necessary. This is the most common form of switching operation.

There are two methods of generator synchronising:

•Super-synchronously synchronising, with the incoming frequency higher than the running frequency.

•Sub-synchronously synchronising, with the incoming frequency lower than the running frequency.

2.3 Generator synchronising

Power station generators will also operate as synchronous motors, i.e., instead of being mechanically driven to produce electrical power, they run as motors, drawing power from the system. Without further adjustment of the governor, this will occur on synchronising if done sub-synchronously or possibly after synchro - nising with the two frequencies almost equal, should the system frequency rise immediately. Motoring can

SYNCHRONISING VOLTS r

I V,)

SYNCHRONISING

CURRENT

NOT TO SCALE

FIG. 12.5 Voltage error

a lagging de-magnetising current flows from the system to the generator to weaken the generator magnetic

2.4.2 Phase error

The immediate effect after synchronising with the generator incoming voltage V, displaced behind the system running voltage V, by an angle 0 is shown in Fig 12.6. The voltage phasor between corresponding phases V s , results in the generator drawing a synchronising current

from the system. As the stator impedance is predominantly reactive, this is nearly in quadrature with voltage V„ which is nearly in phase with the running voltage V,. Real power is taken from the system which produces the torque required to pull the rotor into synchronism.

The converse also applies if the incoming voltage V; leads the running voltage V,. The generator produces a synchronising current, the active component of which produces the required synchronising torque.

2.4.3 Frequency error

If the generator incoming frequency (fi) is slightly greater than the system running frequency (f r ) on syn-

SYNCHRONISING

VOLTS (V S )

INCOMING

VOLTS (V)

RUNNING

VOLTS ( Vd

NOT TO SCALE

Fro. 12.6 Phase error

chronisation the incoming and running voltages are superimposed onto each other; the resultant voltage, represented by the voltage (V,), is a pulsating wave whose magnitude at any instant is the voltage difference (V, V r ) as shown in Fig 12.7. This voltage is obtained by reversing the phase of the running voltage (V,) and adding the reversed wave to the incoming voltage (V,). This results in a synchronising current (I s ) being drawn from the higher frequency generator sup. ply, the real power component of which produces the synchronising torque required to achieve synchronism.

Similarly, if the situation is reversed and the system running frequency is higher than the generator frequency, then real power is taken from the system.

If the frequency difference in Fig 12.7 continues, the amplitude of the resultant pulsating voltage continues to increase with each cycle until a maximum of (Vi + V r ) is reached when the two voltage waves are in antiphase. If further continued, the resultant voltage progressively decreases as the two voltages move back into phase. The envelope of the modulated wave (V, — V,) is shown dotted. The beat frequency of the modulated wave is equal to the slip frequency. If the slip frequency is small, e.g., 0.05 Hz or 20 s/slip cycle, it takes 10 seconds for the resultant voltage to rise from being zero at phase coincidence to peak value.

With the voltage and phase matched, the synchronising current produced by a small slip frequency is generally not significant since the change to a high resultant voltage is not rapid. It also follows that if the voltage and phase error are small, this does not greatly increase the synchronising current.

2.5 Faulty synchronising

For each synchronising condition, as the error increases in magnitude so does the disturbance or shock this imposes on the generator and the system. In particular, large phase displacement and frequency differences result in generator hunting, a condition where the synchronising torque accelerates the rotating system, overpowering the rotor damping, etc., resulting in the rotor swinging past the synchronous position under its own inertia. An opposing torque is produced to retard and reverse the direction of motion, the cycle continuing until eventually the oscillation is reduced by damping and the rotating system held in the synchronous position. To produce the fluctuating torque required, the generator has to alternately supply and absorb sizeable synchronising power with an initial transient which can involve currents in excess of generator rating. Mechanical forces are proportional to the squares of the currents with the maximum mechanical force related to the peak current value. In this respect, the duration of the synchronising torque is not as important as the magnitude and number of force reversals. The heavy power transfer results in a voltage disturbance which may also adversely affect the power system to which the generator is connected, although

It is highly unlikely that this would result in transient instability of the system.

The parameters which determine the power swing on the system can be summarised as:

•Phase angle and slip frequency between the two voltages.

•Voltage magnitude and system loop impedance.

•Relative size of the generator and system (connected capacity, inertia and fault level).

•Speed of governor response.

•Mechanical damping of the turbine-generator rotating system.

The effect of the disturbance on a turbine-generator is to stress the stator and rotating parts, depleting design life expectancy in certain respects, typically:

•Stator end windings, being the weakest part of the stator, may distort and in so doing, damage the end insulation. Although there is little likelihood of permanent deformation, small elastic deflections may eventually adversely affect the insulation.

•Torsional oscillations stress the shaft system and in particular the shaft couplings.

•LP turbine blade root stress due to the effects of blade dynamics.

If the divergence in slip frequency is sufficiently large, the pullout torque of the rotor is exceeded and generator pole slipping occurs.0Faulty synchronising at a phase angle of about 120 gives rise to high shaft torques and stresses, which may exceed those resulting when a three-phase short-circuit is cleared.

3 Synchronising methods

Two quite different methods have been developed for synchronising. The first and oldest method, dating back to the nineteenth century, is performed by the operator and is called

For many years, manual synchronising was carried out using a set of three lamp bulbs. These were connected across the supplies to measure the sum of the two voltages. When the two voltages were equal and in phase, the voltage across the lamps was at maximum and the lamps were at their brightest. This was known as the 'lamp bright' method. Today, the correct synchronising conditions are determined by observing a set of instruments.

The second method and employs a purpose designed control unit to perform the complete operation without any need of supervision by the operator. Automatic synchronising is initiated within the operating range of the control unit by the operator, or by an auxiliary relay if incorporated into a larger automatic control scheme.

Both methods are used for system and generator synchronising but only automatic generator synchronising incorporates voltage and frequency control. At a power station, system synchronising is carried out manually and generator synchronising is normally carried out automatically, using a device called an automatic synchronising relay. Manual synchronising facilities are provided as back-up for generator synchronising in case the automatic synchronising relay fails. Both methods are also used for system synchronising at transmission stations. Automatic synchronising employs a device called a system synchroniser used, for example, in autoswitching schemes such as delayed auto-reclose.

3.1 Manual synchronising

The instruments provided for manual synchronising are an incoming voltmeter, a running voltmeter, a phase angle voltmeter (i.e., an instrument which measures a voltage corresponding to a phase angle) and a synchroscope which measures slip frequency and phase.

The three voltmeters are used to synchronise when conditions are synchronous, i.e., system synchronising. The incoming and running voltmeters plus the synchroscope are used to synchronise when conditions are asynchronous, i.e., generator synchronising, and when needed for system synchronising.

In brief, to system synchronise, both voltages are first measured and compared. With zero frequency difference shown by the synchroscope, the phase is measured with the phase angle voltmeter. If both voltage and phase measurements are within prescribed li mits, as is normal, the switch is closed. To generator synchronise, one voltage (which may be the incoming or running voltage) is adjusted as necessary to reduce any voltage difference to within prescribed limits. The incoming frequency is then adjusted until the slip frequency is less than the maximum allowed. For load pick-up the adjustment must produce the incoming frequency high and falling to super-synchronously synchronise. Switch closing follows as soon as the phase is within prescribed limits and is initiated at the instant the phase is at the correct advance angle, or as close to this as can practicably be achieved.

Repetition of the synchronising instruments at each switch control position at which synchronising facilities are required is not necessary. The synchronising instruments themselves may be used to synchronise at any switch control position if the voltmeter scales are changed, these are therefore combined (as far as is allowed) into a common set. The synchronising instruments are housed in a mobile trolley to ensure that the indications are clearly legible at each switch control position if located at more than one control panel, as is the case in a power station. To accommodate four system voltage levels (i.e., 3.3 kV, 11 kV, generator and transmission voltages), two separate sets of instruments are provided, each with dual scale voltmeters.

To transfer the instrument circuitry, the trolley i s equipped with two leads and plugs, and each switch control position at which synchronising facilities are required is provided with a synchronising socket (this is not always necessary and a common socket may be provided at a convenient point). Prior to use, the synchronising trolley is positioned adjacent to the switch control position concerned and plugged into the socket to prepare the circuitry for synchronising.

The level of operator ability required depends on the switching operation, but at least demands a technical understanding of the principles involved and o r the accuracy that must be applied. For system synchronising, the operation normally amounts to little more than a check of voltage and fixed angular displacement and little skill is involved. With a frequency difference, the full procedure is required. As the slip frequency is reduced, sensitive adjustments to primemover speed need to be made to obtain the desired response.

The characteristics of the prime-mover governor may also lead to some change of slip near the point of closing the switch. In particular, attention must be paid to the selection of the correct advance angle for initiating the switch closure, estimated from the product of the observed slip frequency in ( ° elec)/s (estimated from the time taken for the phase to traverse a given angle, e.g., 3600 ) and the known switch closing time for the switch concerned. From experience, this process is often simplified to a fixed angular allowance.

In addition to being competent in the above respect, the operator must be fully aware of the function he is performing and conscious of the consequences of error and the result of incorrect operation so that no chances are taken.

As a safeguard against the risk of human error or malfunction of the synchronising instruments resulting in the connection of unsynchronised supplies, a device called a check synchronising relay is added. This separately measures the voltage, phase and slip frequency, inhibiting the switch closing signal unless the supply differences are within preset limits. The employment of this relay is termed check operative. To assist the operator, a 'check synch monitor' lamp can be added to indicate when satisfactory synchronising conditions are present. The slip feature is switched out of service for generator synchronising to permit the switch to be closed with a slip frequency greater than the relay setting permits, as required for load pick-up. (If motoring is not a consideration, e.g., gas turbines, this feature may be retained if preferred for operational reasons.) Check synchronising relays are also used as system synchronisers in auto-switching schemes at transmission stations. In this application, the check synchronising relay initiates the switch closing signal when the differences between two supplies are within preset limits.

The synchronising equipment is also provided for manual override synchronising, i.e., when one supply