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Home / Technical Articles / Practical implementation of the six most common transformer protection principles

Best transformer protection vs cost

This technical relies on the previously published article (6 alarms coming from a substation transformer you MUST take very seriously), but is much more dedicated to the implementation of relay protection principles. You know that transformer is one of the most important links in a transmission system. Unfotunately, its great range of characteristics and special features makes complete protection difficult.

Practical implementation of the six most common transformer protection principles
Practical implementation of the six most common transformer protection principles

The choice of suitable protection for transformers also is governed by cost, as the ratings required in transmission, and distribution systems, range from a few kVA to several hundred MVA.

Fuses are used for the lower rated transformers. Higher ratings, however, require the best protection that can be designed.

The most common principles adopted in transformer protection include the following:

  1. Overheating protection
  2. Overcurrent protection
  3. Earth fault protection (restricted and standby)
  4. Biased differential protection
  5. Gas detection protection, and
  6. Overfluxing protection (large transformers or where a risk of over flux exists).

1. Overheating Protection

The rating of a transformer is based on the temperature rise above an assumed maximum air temperature. An oil temperature of about 95°C is considered to be the maximum working value beyond which a further rise of 8-10°C will have a detrimental effect on the transformers insulation. It will lower the life of a transformer, if sustained.

Large transformers have oil and/or winding temperature detection devices. Both direct (oil) and indirect (winding) methods of temperature measurement may be employed, or a combination of both.

Generally, these devices are fitted as shown in Figure 1.

Typical instrument for direct measurement of temperatures
Figure 1 – Typical instrument for direct measurement of temperatures

LEGEND:

  • A – Temperature sensitive bulb
  • B – Capillary tube
  • C – Bourdon tube
  • D – Connecting rod
  • E – Main spindle
  • F – Plate carrying mercury switches
  • G – Mercury switch in alarm circuit
  • H – Mercury switch in circuit of motor associated with coolant circulation
  • K – Mercury switch in contactor circuit of power lines

  • L – Adjustment for operation point of mercury switch G
  • M – Adjustment for operation point of mercury switch H
  • N – Adjustment for operation point of mercury switch K
  • O – Maximum pointer
  • P – Scale
  • Q – Audible warning device
  • R – Signal lamp
  • S – Electric motor associated with coolant circulation (air/oil)
  • T – Indicating pointer
  • U – Ambient temperature compenstator

The direct method for an instrument measuring oil temperature is shown in Figure 1 above. The temperature detecting element comprises a mercury filled steel bulb A. This is connected by a capillary tube B to a Bourdon tube C, which is fixed at one end.

Increases in temperature cause expansion in the mercury, resulting in increased pressure in the Bourdon tube. This causes the free end to deflect. The deflection causes the plate F to rotate.

Mounted on this plate are several switches. The position of these switches determines the time and sequence of their operation, that is, how much the plate must rotate to initiate operation. Note that older devices use mercury switches, modern transformers have micro switches as they don’t operate due to vibrations caused by earthquakes or through faults.

Compensation for changes in air temperature is provided by the shaped bimetallic strip U fitted in the linkage between the Bourdon tube and the metal plate. Pointers T and O indicate the actual temperature of the bulb, as well as the maximum temperature to which it has been subjected.

The switches carry out the trip and/or alarm functions.

The same principle may be applied for the indirect method which measures the temperature of a transformer winding. A different type of detecting element is used from the plain bulb shown.

The mercury bulb is surrounded by a heater coil or a heater is included in the instrument. This is fed from a current transformer which reflects the actual current in the transformer winding. If the heater is suitably designed, the instrument can be arranged to measure either the winding average or ‘hot spot’ temperature. The hot spot temperature is more commonly used. (Note that the hot spot is the hottest spot in the windings caused by local heating.)

Generally, two winding temperature instruments are fitted to the larger power transformer. Each instrument is fitted with up to four switch contacts.

The winding temperature instrument is arranged to start cooling fans and pumps, and to give an alarm (120°C) and trip (130°C). The oil temperature instrument is also arranged to give an alarm (95°C) and trip (105°C), usually the lower voltage circuit breaker.

Table 1 shows typical settings for these instruments.

Table 1 – Typical temperature settings

Winding Temperature Oil Temperature
Instrument 1 Instrument 2
Coolers In 90°C
Out 73°C
Alarm 95°C
Alarm 120°C
Trip 130°C

Note In cases where forced cooling is not used, usually only an oil temperature instrument is fitted.

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2. Overcurrent Protection

Protection against excess current was the earliest evolved protection system. From this basic principle, the graded overcurrent system was introduced for fault protection. Most system disturbances utilizing this method are detected with IDMT relays, that is, relays having:

  1. Inverse characteristic (the larger the fault current, the quicker is the operation), and
  2. Definite minimum time of operation.

The degree of overcurrent protection provided to a transformer by an IDMT relay is limited. Usually, settings of these relays must be high, that is, 150% to 200%. This is because the relays must not operate for emergency overload conditions.

Therefore, these relays provide negligible protection for faults inside the transformer tank.

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3. Earth Fault (Restricted)

Generally, the simple overcurrent and earth fault scheme used in a typical line protection application does not give adequate protection to a star connected winding.

The degree of protection is greatly improved by the application of a unit differential earth fault scheme (or restricted earth fault protection). This is shown in Figure 2. This diagram shows a high impedance relay.

The protection system is operative for faults within the zone of the current transformers. Virtually complete cover for earth faults is obtained, particularly when the star point is solidly earthed.

Restricted earth fault connection for star connected transformers with neutral solidly or resistance connected earth
Figure 2 – Restricted earth fault connection for star connected transformers with neutral solidly or resistance connected earth

Star and delta windings can be protected separately with restricted earth fault protection. This provides high speed protection against earth faults for the whole of the transformer with relatively simple equipment.

A typical earth fault protection for delta connected windings is shown in Figure 3. This diagram shows that the restricted earth fault scheme also protects the earthing transformer (an earth reference used to limit earth fault current).

The earthing transformer is protected by the main transformers differential and tank overpressure device (Buchholz).

Earth fault protection delta connected windings
Figure 3 – Earth fault protection delta connected windings

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4. Differential Protection

Differential protection is designed to cover the complete transformer. This is possible because of the high efficiency of transformer operation and the nearly equal ampere turns developed in the primary and secondary windings. (MVA ‘in’ approximately equals MVA ‘out’).

This type of protection scheme compares current quantities flowing into the network with quantities flowing out of the network. The difference between these values is referred to as the ‘spill’ current available for operation of the protection relay.

The principal causes of the spill current include the following:


Transformer Ratio

The rated currents on the primary and secondary sides differ in inverse ratio to the voltages. This difference is overcome mainly by the appropriate selection of current transformer ratios.


Tap Changing Facility

If the transformer has a tapping range, the voltage variation must be allowed for in the differential scheme. This is because the current transformers and connections are selected to balance at the nominal tap ratio of the transformer. Any variation in ratio away from the nominal tap position will produce an imbalance proportional to the voltage ratio changes.

Under certain conditions (particularly out of zone fault conditions), this imbalance current may be sufficient to operate the relay when operation is
not required.

To offset these spill effects, the protection relay selected usually includes a proportional amount of bias.


Magnetising Current Inrush

When a transformer is energized initially, magnetising current is required. The current appears only on the primary side of the transformer, therefore, the whole of the magnetizing current appears as an imbalance to the differential protection.

Since this phenomenon is only transient, stability of protection may be maintained by the use of a second harmonic restraint, being the most widely used to prevent the operation of magnetizing inrush current. This is because the waveform produced by inrush currents has a significant amount of second harmonics.

A typical oscillogram of transformer inrush currents, due to magnetizing the transformer core, is shown in Figure 4.

Transformer magnetizing inrush current typical oscillogram
Figure 4 – Transformer magnetizing inrush current typical oscillogram

The initial peak value of the inrush current in any phase depends upon the instant of switching and the residual magnetic condition of the core. The maximum peak values equal up to 8 times the rated current of the transformer.

The basic unbiased scheme applied to a delta/star transformer is shown in Figure 5 below.

Balance is obtained by using star connected current transformers on the delta side of the transformer and delta connected current transformers on the star side with the correct ratio.

Differential protection basic unbiased scheme applied to delta/star transformer
Figure 5 – Differential protection basic unbiased scheme applied to delta/star transformer

The protection of power transformers with variable ratio (due to on load tap changing equipment) must include a bias feature, if low fault setting and high operating speed are to be obtained.

A high speed biased differential relay, incorporating a harmonic restraint, will prevent relay operation for any variance in ratio which is due to tap changing and for the effects of magnetizing inrush current.

The basic biased scheme applied to a delta/star transformer is shown in Figure 6.

Differential protection basic biased scheme applied to delta/star transformer
Figure 6 – Differential protection basic biased scheme applied to delta/star transformer

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5. Gas Detection

Faults inside oil immersed electrical plant (for example, transformers) cause gas to be generated. If the fault is severe, oil movement occurs.

The generation of gas is used as a means of fault detection in the gas/oil operated relay. This comprises one or two hinged vanes, buckets, or similar buoyant masses inserted into the pipework between the oil conservator and the transformer tank.

Figure 7 shows its general application.

The floats are held in equilibrium by the oil. The rising bubbles (produced by the slow generation of gas due to a minor fault) pass upwards towards the conservator. As they are trapped in the relay chamber, a fall occurs in the level of oil inside the chamber. This results in a movement of the float, closing a pair of contacts in a mercury or reed switch which initiates an alarm.

A heavy fault will produce a rapid generation of gas. This causes violent displacement of the oil which moves the surge float system of the relay. It results in the closing of another pair of contacts (surge contacts) which are used to trip the transformer circuit breakers.

Typical location gas detection relay (Buchholz relay)
Figure 7 – Typical location gas detection relay (Buchholz relay)

The gas/oil operated Buchholz relay is shown over in Figure 8. This relay gives the best possible protection against conditions such as incipient (low level) winding faults, core faults and short circuit situations.

The alarm element will operate for loss of oil, as will the trip element if the oil loss continues. This alarm and trip will sometimes operate under cold conditions if conservator oil levels are not maintained.

Analysis of a gas sample collected in a Buchholz chamber frequently may assist diagnosis of the type of fault. The rate of gas generation indicates the severity of the fault.

Tap changer selector switches, mounted separately from the main oil tank, can be provided with a separate oil/gas actuated relay. Alternately, the pipework may be arranged in such a manner that one relay is used for both tanks.

One of the biggest problems associated with older gas/oil actuated protection using mercury switches is vibration (for example, earthquakes, etc.) It may cause maloperation, however, the problem has been overcome by using reed relays in place of the older type mercury switch.

Transformers are fitted with pressure relief devices to prevent tank rupture in the event of a major internal fault.  The old type consisted of a thin diaphragm at the top of a relief vent. The new type is a spring loaded self-resetting diaphragm which also activates a micro switch to trip the transformer.

Gas detection relay and gas receiver (Buchholz relay)
Figure 8 – Gas detection relay and gas receiver (Buchholz relay)

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6. Overfluxing

Transformer overfluxing is caused by overvoltage and/or a reduction in system frequency. Overvoltage causes an increase in the flux generated and stress on insulation. The increased flux density causes an increase in iron loss and an increase in magnetising current.

Flux is diverted from the laminated core of the transformer into the steel structure. This gives rise, particularly, to the core bolts carrying more flux
than their designed limits. Under these conditions, the core bolts may be rapidly heated to a temperature which destroys the insulation surrounding them.

This could damage the core insulation.

Reduction in frequency has the same effect of increasing core flux, therefore, it follows that a transformer can operate with some overvoltage, provided it is accompanied by an increase in frequency. However, the operation must not continue for prolonged periods with high voltage and low frequency conditions.

The ratio of voltage/frequency (V/f) should be less than or equal to 1-1, where the transformer’s highest designed operating voltage and nominal system frequency are taken respectively as unity.

Overfluxing protection is used mostly on generator/transformer units. Overfluxing may occur when generators are run up for synchronisation to the system.

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Source: Switching Operator’s Manual – Transmission Switching by Horizon Power

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author-pic

Edvard Csanyi

Electrical engineer, programmer and founder of EEP. Highly specialized for design of LV/MV switchgears and LV high power busbar trunking (<6300A) in power substations, commercial buildings and industry facilities. Professional in AutoCAD programming.

4 Comments


  1. Hudson Tangayi
    Jul 26, 2019

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    Jul 25, 2019

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  3. zuproc66
    Jul 25, 2019

    Nice article. Very informative.

    In Figure 1, mercury is already a banned substance. Any new materials replacing Mercury and its details? Thank you.


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    Jul 24, 2019

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