19 Nov 2015


1.1       GENERAL

In onshore installations main electric power is taken in bulk from the National Grid through Area Boards at voltages up to 33kV.  In offshore installations however main power must be generated locally, and this is usually done at 6.6kV.
Note that 6.6kV is a nominal rating; in practice generation is more usually at 6.8kV to allow for voltage drop in the network.
There are instances of generation at other levels, but these are always ‘high voltages’.  Some large loads are fed directly from the HV system, but for most purposes the supplies are needed at low voltage, typically 440/250V offshore and 415/240V onshore.  These are provided through 3-phase power transformers.



1.2.1    General
Power transformers are always enclosed in a tank or similar protection.  They may be liquid cooled, air cooled or dry type (encapsulated or open).  If liquid cooled, the coolant may be mineral (hydrocarbon) oil, silicone oil or some artificial liquid such as ‘Askarel’.
The internal construction of all power transformers is similar.  The windings are stacked around a 3-limbed laminated iron magnetic core, the low-voltage windings innermost and the high-voltage windings outside them - the best arrangement for insulation.  It can be seen in the cut-away portion of Figure 1.1.  Ducts are arranged through both windings on each limb to assist cooling.  The terminations of the windings are brought out to cable boxes for external connections (see para. 1.8) or, for large outdoor transformers, to terminal bushings.

1.2.2    Liquid (Oil) Filled Transformers

The largest bulk-power transformers are usually in a single tank, completely filled with oil and with a header tank called a ‘conservator’ on the roof.  This maintains a static head of pressure on the oil and also allows free expansion and contraction.  The transformer of Figure 1.1 is of this type.
In the pipe connecting the main tank to the conservator there is often inserted a device called a ‘Buchholz Relay’.  It has two elements: one traps and collects any small gas bubbles evolved at a winding due to the early stages of a possible breakdown of insulation.  If sufficient gas has accumulated, a float switch gives an alarm.  The other element is a pivoted vane.  If a major fault occurs inside the tank, the displaced oil surges past the vane, causing it to swing, make a contact and trip the supply breaker.  The Buchholz relay is further described in the manual ‘Electrical Control Devices’.
The oil coolant is heated by the I2R losses of the currents in all the windings and also by the iron losses. It circulates through a closed cooling system by thermosyphon action (in a few cases by pumping).  Heat is extracted from the coolant through radiating tubes or fins either by natural convection, by forced cooling from fans or, more rarely, by water cooling.  The cooling of transformers is dealt with more fully in para. 1.6.  The whole arrangement can be seen in Figure 1.1.
Facilities are provided for oil filling, draining and sampling for test.  Oil samples are taken periodically for insulation testing in the laboratory, where they are examined for deterioration or water pollution.
A tapping switch, normally for off-load use only, is usually fitted for changing the transformer taps. The larger system network transformers may have on-load tap-changing gear - see para. 1.9 for details.
Smaller oil-filled transformers are usually sealed, with an air space above the oil instead of a conservator, to allow expansion when hot.  In appearance they would look like the Askarel-filled type shown in Figure 1.2.
Silicone oil is increasingly used instead of mineral oil because it is non-flammable.  The construction is however similar.

1.2.3    Liquid (Askarel) Filled Transformers

In onshore installations where transformers can be installed at a distance from other plant, the fire risk is no greater than normal, and mineral oil-filled transformers are generally used.  Offshore however the fire risk is crucial, and other designs of transformer are necessary.

For this reason power transformers on offshore installations do not use mineral oil as the insulating and cooling medium.  Instead, a non-flammable silicone oil or a non-flammable liquid such as Askarel is used which is sometimes described by a trade name such as ‘Pyroclor’ or ‘Pyralene’.
The basic transformer design using silicone instead of mineral oil is no different from that described for oil-filled transformers.  But Askarel, apart from its fire-resistant properties, has other characteristics, namely:
·         it is expensive,
·         it evaporates readily when in contact with air,
·         it is very penetrating,
·         it is heavy,
·         it is toxic and must not be allowed to come into contact with the skin or eyes,
·         it must on no account be discharged into the sea because it is non-biodegradable.
The external appearance of a typical Askarel-filled transformer is shown in Figure 1.2.  Its internal construction is as described in para. 1.2.1, but, additionally, the transformer is hermetically sealed to prevent loss of liquid by evaporation.  In some designs the main cover flange joint is welded up, as is also the filler plug after filling with liquid, and sometimes even the drain plug.  The expansion space above the liquid is filled with dry air or inert gas and has sufficient volume to ensure that the pressure inside the tank is limited to a safe value even at maximum temperature and expansion.  A pressure/vacuum gauge is fitted.  It indicates zero at normal temperature, a positive pressure at high temperature and a partial vacuum at low temperature.  This gauge is a constant monitor on the state of the sealing.  A sight-glass also gives a direct measure of the liquid level at all temperatures.




The off-load tapping switch spindle has five positions.  Because  Askarel is a penetrating liquid it is not easy to provide an adequate seal where the operating shaft of the tapping switch comes through the tank-wall of the transformer.  Some designs rely on a simple packing gland whereas others back this up by enclosing the whole tapping switch handle in an auxiliary box with a bolted cover.  This box is filled with Askarel and provides a second barrier to prevent liquid from leaking out of the main tank.  With the latter design it is necessary to drain and open up the auxiliary box to get at the tapping switch handle.
If a fault develops inside the transformer, the Askarel breaks down and forms a gas leading to a gradual or sudden rise in pressure, depending on the severity of the fault.  To prevent the transformer tank from splitting, a spring-loaded ‘Qualitrol’ pressure relief device on the top operates to release the excess pressure; at the same time contacts within the device close to trip the incoming supply and give an alarm.  Pressures encountered in normal service are not high enough to operate the device, which is essentially an emergency relief valve.  The Qualitrol device is further described in the manual ‘Electrical Control Devices’.
In case the tank should ever crack or split and so spill the Askarel, these transformers are always erected with a sill around their mounting places.  The sill is high enough to contain the entire filling of its transformer and to prevent the toxic liquid spreading.  After a spill the liquid must be collected and put into containers, along with mopping-up rags, and sent ashore for disposal.  ON NO ACCOUNT MAY THEY BE DROPPED INTO THE SEA.  Personnel cleaning up must wear protective clothing, gloves and goggles.
Though widely used offshore at first, Askarel-filled transformers are gradually being phased out in favour of silicone oil-filled types because of the toxic nature of Askarel.

1.2.4    Dry Type Transformers
On some offshore installations transformers are used where the windings are encapsulated in epoxy resin and the whole block is air cooled.  To assist the cooling, air ducts are arranged through the solid encapsulation.
Such transformers are often given a dual rating (e.g. 2 000/2 500k VA): the lower one where the cooling air circulates naturally, and the higher one where it is assisted by fans.  It is arranged that the fans start automatically when the loading of the transformer exceeds the lower rating.
Dry-type power transformers can readily be built into their own LV distribution switchboards to form a single unit, thereby saving LV cable boxes and cables and bringing the incoming feeder copperwork right up to the transformer’s LV terminals.
Small low-voltage transformers used as part of other equipment - for example, in battery chargers or inverters - are usually open type, air cooled without any enclosure.  They may be 3-phase or single-phase.  Such open-type transformers are protected by being housed within the parent equipment’s main enclosure.

1.3       RATINGS

The capacity of transformers is always given in kVA or MVA, because the heating depends only on the actual current and is not affected by the power factor of that current.
The ratings of most offshore power transformers extend over a range of about 400kVA to
2 500kVA, depending on their duty.  In onshore installations the ratings may go up to 30MVA or more; National Grid sizes may go up to 750MVA.

A transformer is designed to give a nominal secondary voltage from a nominal primary voltage - for example 11 000/415V or 6 600/440V.  Due to voltage drop within the transformer itself, the actual turns ratio must be somewhat lower than this if the nominal secondary voltage is still to be achieved at full load.  In the two examples cited above the turns ratio (that is, the no-load ratio) would need to be about 11 000/435V and 6 600/460V respectively.
Alone among electrical plant, transformers are required by British Standards to have their no-load rating displayed on their nameplates (generators and motors have their full-load ratings).  The nameplate figure is therefore sometimes misleading in that it suggests a 435V or 460V system, whereas the nominal system voltage is still 415V or 440V.  In some documentation only nominal voltages are normally used, notwithstanding any transformer name-plate figures.  Errors due to this misunderstanding may often be found on other drawings.


In a manner similar to generators, transformers present impedance to the flow of through-currents.  This impedance is measured by the percentage voltage applied at rated frequency to the primary winding necessary to circulate full rated current in the secondary when short-circuited.
The effect of transformer impedance is to cause an internal voltage drop when load current is passed through the transformer.  Exactly as with a generator, the greatest drop is caused when a reactive current passes through the reactance of the transformer.  (The vectorial treatment of impedance loading on a generator is fully covered in the manual ‘Electrical Generation Equipment’, Chapter 4.)
The internal drop due to load current causes a reduction of the secondary terminal voltage below its open-circuit level.  This reduction, usually expressed as a percentage of the no-load voltage, is termed the ‘regulation’ of the transformer under the stated load conditions.  Since the impedance of a transformer is almost wholly reactive, it follows that the greatest regulation occurs when a highly reactive load is applied.
If E is the nominal rated line voltage applied to the primary winding, and if Esc is the line voltage which, when applied to the primary, will circulate full rated current in the short-circuited secondary, then
Esc is called the ‘impedance voltage’ of the transformer and is usually expressed as a percentage of EThis same percentage gives the value of Z, which is the ‘percentage impedance of the transformer’.
This impedance is almost pure inductive reactance and ranges in value from about 5% to 10% for the sizes of transformers in use.  The measured percentage impedance is marked on each transformer nameplate and is used, together with other circuit impedances, to calculate the symmetrical short-circuit level on the low-voltage system. (See the manual ‘Electrical Protection’.)
At the instant of switching on a transformer, while the core is unfluxed and therefore offers no reactance, a large ‘inrush current’ will flow which, although transient, may achieve a value of up to five times full-load primary current.  This disappears quickly after switch-on.
Once the core is magnetised, the impedance of a transformer to fault currents is constant; this contrasts with a generator whose reactance changes from subtransient through transient to synchronous as a fault progresses.

1.5       INSULATION


1.5.1    Dry Type Transformers
The maximum temperature to which the windings of dry-type transformers may be allowed to rise depends on the type of insulating material round the conductors. These transformers are classified according to the insulating material used, and to each class is allotted a maximum ultimate temperature. The classification is as follows (according to BS 171 : 1970 and BS 2757 : 1956):
Typical Insulating Material
Ultimate Temperature
Impregnated cotton, silk, etc.; paper; enamel
Paper laminates; epoxies
Glass fibre, asbestos (unimpregnated); mica
Glass fibre, asbestos, epoxy impregnated
Glass fibre, asbestos, silicone impregnated
Mica, ceramics, glass, with inorganic binders
> 180oC
It should be noted that the classification letters do not follow an alphabetical sequence.  This is because there were originally only three classes - ‘A’, ‘B’ and ‘C’.  Later intermediate classes were added, and it was decided not to disturb the original well-understood three.
Certain of the higher-temperature materials may be hygroscopic and therefore not always suitable in any particular environment, particularly where dampness is severe.
It should be particularly noted that the classification depends on the ultimate temperature to which the insulating material may be subjected, for it is this which determines whether or not it will suffer damage when heated.  It does not depend on temperature rise alone.  If, for instance, the ambient temperature is 40oC, a Class ‘B’ material may be used if the designed temperature rise will not exceed 90oC, so making the ultimate maximum temperature 130oC.  Designed temperature rises must therefore take into account the greatest expected ambient temperature in which the transformer will operate.

1.5.2    liquid Filled Transformers

Liquid-filled transformers are not classified for insulation as are the dry type.  There is an overall requirement that the temperature rise of the windings shall not exceed 65oC, and that the temperature rise at the top of the liquid shall not exceed 60oC if the transformer is sealed or has a conservator.

1.6       COOLING

The cooling system of a given transformer is identified by a 4-letter code, as follows:
                                   1st and 3rd letter:          kind of cooling medium
                                   2nd and 4th letter:         kind of circulation
The code symbols for the first and third letters are:
                                   Mineral oil                                    O
                                   Synthetic insulating liquid            L
                                   Gas                                              G
                                   Water                                           W
                                   Air                                                A
                                   Solid insulant                               S

The code symbols for the second and fourth letters are:
                          Natural circulation              N
                          Forced circulation               F
Examples of the use of this code are:
                 Oil-filled, thermosyphon circulation, natural ventilation                   ONAN
                 Askarel-filled, thermosyphon circulation, natural ventilation           LNAN
                 Dry-type encapsulated, fan cooled                                                 SNAF
                 Oil-filled, pumped circulation, water cooled by pump                     OFWF


A 3-phase transformer has a 3-limb core. For transformers designed to BS 171 the terminals of the windings mounted on each limb are identified by a letter as shown in
Table 1 overleaf.

Designating Letter
Limb 1
Limb 2
Limb 3
     High Voltage
     Low Voltage
     Tertiary (if fitted)
The external connections to the high- and low-voltage windings are brought out of the tank
through bushings.  These terminals are labelled using letters appropriate to the winding concerned as shown in Figure 1.3.  When viewed from a position facing the high-voltage side of the transformer, the phase sequence is A-B-C from left to right.  The subscript numbers identify the winding terminations, including tappings, numbered in the direction of the applied or induced voltage at a given instant.
Three-phase windings can be connected in delta, star or zig-zag (not very common); the star or zig-zag connection must be chosen if a star-point is required to provide a neutral for a 4-wire system or for earthing.  A common arrangement for 3-phase power transformers in both onshore and offshore installations is for delta-connected high-voltage windings and star-connected low-voltage windings, with the star-point brought out to provide a neutral and earth for the low-voltage system.
A delta-connected winding is designated by the letter ‘D’, a star-connected winding by ‘Y’ and a zig-zag winding by ‘Z’.  Capital letters are used for the high-voltage windings and lowercase for the low-voltage.  Thus ‘Dy’ stands for delta HV/star LV; Yy for star HV/star LV, and so on.  When the star-point of a star-connected winding is brought out it is designated ‘YN’ for a high-voltage or ‘yn’ for a low-voltage winding.
The winding connections for a delta/star transformer having a delta-connected high-voltage winding are shown in Figure 1.4, which also shows the vector relationship between the voltage applied to each high-voltage winding and the induced voltage in each corresponding low-voltage winding, the reversal between secondary and primary being ignored.
Taking the phase-to-neutral vector of ‘A’ phase high-voltage as reference vector at
12 o’clock, the corresponding ‘a’ phase low-voltage vector leads by 30o and is therefore at 11 o’clock.  Thus the vector symbol in this particular connection arrangement is ‘Dy11’, which describes the high- and low-voltage winding connections and the angular displacement between primary and secondary voltages.  Other winding arrangements are sometimes used, and for full particulars of these, together with their vector symbols, reference should be made to BS 171 - Specification for Power Transformers.
In the case shown above the vector symbol is sometimes written ‘Dyn11’ to draw attention to the neutral’s being brought out on the secondary (low-voltage) side.
Transformers of different vector groups must not in general be paralleled.  If all the primaries are supplied from a common source, the secondaries of differing groups such as Dy11, Dy1, Yy0 will have different phase relationships.  For example, there will be 60o difference between Dy1 and Dy11 (which leads on it), or 30o difference between Yy0 and Dy1 (which lags on it).  Such out-of-phase secondaries must never be paralleled, even though their primaries may be in parallel.
The exception is that groups with the same clock numbers, such as Dy11, Yd11, Yz11, may be paralleled, provided that there is no other objection, since the secondaries are all in phase.


1.8       CABLE BOXES

The terminals of large transformers which are connected to external lines are brought out through ceramic bushings in the cover (shown in Figure 1.1).  The terminals of other transformers have to be connected to cables.  This applies particularly to transformers on offshore installations and to most transformers in onshore oil installations.
The windings are connected to cables through cable boxes fixed to the transformer tank.  If cables are used on both HV and LV sides, the cable boxes would be on opposite sides of the tank, as seen in Figure 1.2.
On most transformers the current on the HV side is low enough to be carried by a single, 3-core cable which enters the HV box through a sealing gland and divides inside.  Sometimes small current transformers are also fitted inside the cable box.
On the LV side currents are much heavier and often exceed 3 000A.  The LV cable box is therefore much larger.  In order to carry such currents, three, or sometimes four, single-core cables are required for each phase.  This results in the cable runs in the area of a transformer being very heavy and often difficult to accommodate.  In addition there may be two similar-sized cables to carry the neutral, or 4th-wire, current.
On some installations the LV cable box is dispensed with and the windings are connected directly to the switchboard by busbar-type copperwork in an enclosed duct which is brought right up to the side of the transformer.

1.9       TAP CHANGING


1.9.1    General

Tappings are usually provided to vary the transformer’s turns ratio by up to ±5%.  The correct tap is set when the installation is first commissioned and should not need to be changed for a considerable time.  However, as the system load grows over the years, the tapping may need to be changed to maintain the secondary working voltage.  This is normally done on all phases together by means of a switch on the transformer tank and must only be carried out off-load and isolated - that is, with the transformer dead on both sides.  Changes of tap settings may be carried out only by Authorised Persons, and then only on the instructions of the Engineering Department.  All tap changers on offshore and onshore oil installations are of the off-load type.
In the larger shore networks on-load tap changers may be used to maintain system voltage; they are usually remotely controlled from a Control Centre and are described in para. 1.9.3.  On-load tap changers are not used on offshore or onshore oil installations but may be employed on the networks supplying onshore plants.

1.9.2    Off Load Tap Changers

It is usual to provide four additional tappings with off-load tap changers, making a total of five, at 2½% intervals, so that the turns ratio varies by ±2½% ±5%.  Tappings are always placed on the high-voltage side; this allows the lowest possible current rating for the tapping switch itself.  Thus an 11 000/415V transformer with four such extra tappings would be shown on a drawing as ’11 000 ±2½% ±5%/415V’ and would actually give 11 000/394, 405, 415, 425 or 436V on load.  In order to raise the secondary voltage it is necessary to go to a lower (i.e. negative) HV tap.
The tap-changer switch handle can be seen in Figure 1.2.  It must always be kept padlocked against unauthorised or accidental operation.

1.9.3    On Load Tap Changers

Large network transformers which are provided with on-load tap changing normally have a much larger number of taps in smaller steps.  The principle used is ‘make-before-break’: this means that the new tap must be connected before the old tap is broken, otherwise there would be a break in supply and an interruption of full-load current by the tapping switch.
The difficulty with this simple idea is that, during the transition period while both taps are made, a small number of turns of the transformer’s HV winding are short-circuited by the two taps, and a heavy current will flow through them.  Arrangements are therefore made to insert resistance temporarily into this short-circuited loop to limit the current until the tap change is complete and the short-circuit removed. Figure 1.5 shows in principle how this is done.

A, B and C are adjacent taps on an HV winding.  In (a) the tapping is on A, and it is desired to move it, on load, to B.
The moving member consists of a main contact M and two ‘transition’ contacts P and Q which are connected to M each through a resistance.  In position (a) M carries the full load, and P and Q are not in contact.
In the first part (b) of the transition the main contact M is still on tap A.  Contact Q moves to B and contact P is still on A. Q and M now short-circuit the HV turns between A and B, but the short-circuit current is limited by the lower half of the resistance.  Meanwhile M is still carrying the load current from tap A.
At the next stage (c) the moving member has travelled on, and the main contact M leaves tap A. P and Q now share the load current which passes through both halves of the resistance.  These two halves also limit the current in the shorted turns between A and B.
At the next stage (d) the main contact M has moved to tap B, so that it is once again carrying the load current, but now from the new tap.  P however is still on tap A, so that the current from the shorted turns is limited by the upper half of the resistance.
Finally the moving member is at position (e), where the main contact M is on B and carrying the load, while P and Q are out of contact, as they were in position (a), but now on the new tap.
During these transition stages the load current has never been interrupted, nor has the main contact ever been called upon to break any large current.  Moreover the current in the short-circuited turns is always limited by one or both halves of the resistance.
In some designs of tap changer the transition resistors are replaced by reactors.  These have a similar limiting effect but are not a source of heat.  They also cancel each other out magnetically in stage (c) when both are sharing the load.
During stage (c) the full-load current passes momentarily through both halves of the resistance.  To keep them to a reasonable size, they must be short-rated.  This poses the problem that, if the driving motor power should be lost at the moment the mechanism reached stage (c), it would stick there and a rapid burnout of the resistors would follow, with inevitable damage to the short-circuited turns.  Steps must therefore be taken to prevent this happening.

The philosophy is that the power to operate the tap-changer mechanism must never do so directly but should be used only to store energy.  When a tap change is called for, that energy is released and is sufficient to complete the change on its own, even if the external power supply fails.
The stored-energy tap-changer mechanism is usually of one of two types - spring-operated or flywheel-operated.  In the former a motor winds and charges a spring.  A tap change cannot begin until the spring is fully charged, and, once released, it completes the change on its own.
In the flywheel type a motor runs up a flywheel on receipt of a tap-change signal.  When the wheel is up to full speed the motor is disconnected and a clutch engages.  The kinetic energy of the flywheel completes the change on its own.
On-load tap changers and their operating mechanisms are usually separate assemblies bolted to the transformer tank, through which the tappings from all three phases are brought out into the changer compartment.  This too is usually oil filled but separate from the main tank, so that the tap changer can be drained for maintenance without having to drain the main tank.
Provision is made for manual operation, if that should be necessary, by inserting an operating handle.  The speed of the tap change remains the same as with power operation, since the same stored energy is released.


Where a transformer ratio is fairly close - for example 3:1 or less - there is much advantage in both cost and weight in combining the primary and secondary windings, as in Figure 1 6(a).  Such an arrangement is called an ‘auto-transformer’.
In Figure 1.6(a) the secondary winding is combined with the primary, one terminal of each being common; the other secondary terminal is effectively a tap on the primary winding.  This arrangement gives a step-down effect, like a potentiometer, depending on the primary/ secondary turns ratio.  Since the primary and secondary currents are in opposition, the net current in the common part is less than the secondary current alone.  For example, if the primary current were 100A and the ratio 3:1, the secondary current would be 300A, and the net current in the common part would then be the difference, namely 200A.  This part of the winding could therefore be of lighter construction than would be needed if the transformer had been of the normal double-wound type.  Also, because of the closer linkage between the primary and secondary windings, there is less leakage reactance, and the reactance of an auto-transformer is in general less than that of its double-wound counterpart.
Although Figure 1.6(a) shows a voltage step-down arrangement, an auto-transformer can equally be used for stepping up (unlike a potentiometer), as in Figure 1.6(b).  This is possible because the primary flux still links the whole of the secondary winding, so developing in it the full emf determined by the secondary turns.  Use of an auto-transformer is a very economical way of converting, for example, control supplies from 110V to 220V or vice versa.
Because a double-wound transformer provides complete electrical isolation between the two sides, an earth fault on one side is not carried over into the other.  This is not the case however with an auto-transformer.  Both sides are electrically connected through the common terminal and the ‘tap’.
It is important for reasons of safety that, if one line is earthed on one side, that earth should be applied to the common terminal so that it is also applied to both sides, as shown in Figure 1.6(c).  In that case, if the primary voltage were 220V and the secondary 110V, the common earth would ensure that the ‘live’ secondary terminal would never be more than 110V to earth.
A safety hazard would exist if an auto-transformer were wrongly connected, as shown in Figure 1.6(d).  Here the earthed line is not the common one, with the result that there is now no direct earth on the 110V system, one line being at 110V and the other at 220V to earth - a possibly dangerous situation when the secondary circuit is switched in one pole only.
This error can easily arise when domestic equipment which has been designed for the USA 110V system is adapted to operate from the UK 240V supply.  Any such adaptations should always be carefully checked for polarity.



1.11.1  Manufacturers’ Tests
All power transformers are subjected to extensive tests by the manufacturers before delivery to the customer.  While operators and maintenance staff are not responsible for carrying out these tests, it is obviously an advantage to have some knowledge of them.  They are summarised overleaf. If more details are required, reference should be made to BS 171:1970 - Specification for Power Transformers.

Tests by the manufacturer are of three kinds:
Routine          A test to which each individual transformer is subjected.
Type               A test made on a transformer which is representative of other transformers, to demonstrate that they comply with specified requirements not covered by routine tests.
Special           A test other than a type test or a routine test, agreed by the manufacturer and the purchaser, and applicable only to one or more transformers of a particular contract.
Routine tests comprise:
(a)        Measurement of winding resistance, using a d.c. source and taking account of temperature.
(b)        Ratio, polarity and phase relationships, in which the voltage ratio is measured on each tapping.  The polarity of single-phase transformers and the vector group symbol of 3-phase transformers are checked.
(c)        Impedance voltage, using an a.c. source at the rated frequency, and carried out between pairs of windings. Impedance voltage is defined in para. 1.4.
(d)        Load losses, at rated frequency and carried out between pairs of windings.
(e)        No-load losses and no-load current, measured at rated voltage and frequency.
(f)        Induced overvoltage withstand: a test of dielectric insulation using a source of higher-than-rated frequency to avoid excessive excitation current.
(g)        Separate source voltage withstand: similar to (f) but using a source not less than 80% of the rated frequency.
(h)        The insulation resistance of each winding in turn to all other windings, core and frame or tank, all connected together and to earth.  (Note: Where windings are star-connected or delta-connected inside the transformer, phase-to-phase insulation tests cannot be carried out.)
Type tests and special tests are made only if specified by the purchaser. They include:
(j)         Temperature rise test.
(k)        Impulse-voltage withstand tests (with and without chopped waves).
(I)         Measurement of zero-phase sequence impedance.

1.11.2 Users’ Tests
Operators and maintenance staff, while not responsible for the manufacturers’ tests referred to above, are required to apply certain routine checks and tests to power transformers at the intervals laid down in the appropriate maintenance schedules.

These routine tests include:
(a)        Visual examination of the transformer and its earthing resistor (if any), cable connections and earthing arrangements for tightness, mechanical damage, corrosion and signs of overheating.
(b)        Checking the oil or Askarel levels and inspecting for leaks and clear drains.
(c)        High-voltage insulation resistance test on the HV windings.
(d)        Low-voltage insulation resistance test on the LV windings.
(e)        Simulation of overtemperature and overpressure by manual operation of the protection devices, and checking that the alarm indications appear and the circuit-breaker trips.


The protection of electrical installations, including transformers, against damage caused by overload or fault conditions is described in the manual ‘Electrical Protection’.  To summarise, the protection provided for transformers may consist of one or more of the following:
HV Side                  Overcurrent
                                Earth fault
LV Side                  Restricted earth fault
General                  Overpressure (‘Qualitrol’)
                                Buchholz (oil-filled only)


There is a range of small transformers, other than power transformers, which are used to operate measuring instruments, meters and protective relays.  They comprise voltage transformers (VT) and current transformers (CT) and are covered in Chapter 4.

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