Transformer protection -- part 2 [Industrial Electrical Power Systems]

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Types of faults

The following is a brief summary of the types of faults that can occur in a power transformer:

  • • HV and LV bushing flashovers (external to the tank)
  • • HV winding ground fault
  • • LV winding ground fault
  • • Inter-turn fault
  • • Core fault
  • • Tank fault.

Phase-to-phase faults within the tank of a transformer are relatively rare by virtue of its construction. They are more likely to occur external to the tank on the HV and LV bushings. If a transformer develops a winding fault, the level of fault current will be dictated by:

  • • Source impedance
  • • Method of neutral grounding
  • • Leakage reactance
  • • Position of fault in winding (i.e. fault voltage)

Ground faults

Effectively grounded neutral The fault current in this case is controlled mainly by the leakage reactance, which varies in a complex manner depending on the position of the fault in the winding. The reactance decreases towards the neutral so that the current actually rises for faults towards the neutral end.

Current (× full load) Source

Fault position from neutral

++++ Relationship of fault current to position from neutral ( grounded)

The input primary current is modified by the transformation ratio and is limited to 2-3 times the full load current of the transformer for fault positions over a major part of the star winding. An overcurrent relay on the HV side will therefore not provide adequate protection for ground faults on the LV side.

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Resistance grounded neutral For this application, the fault current varies linearly with the fault position, as the resistor is the dominant impedance, limiting the maximum fault current to approximately full load current.

O/C Current (× full load) Source

Fault position from neutral

++++ Relationship of fault current to positions from neutral (resistance grounded)

Substation Liquid Filled Transformer--Available in primary voltages from 2.4 kV to 69 kV in 225 through 20,000 kVA sizes, 600 volt through 35 kV secondary voltage ratings are available.
above: Substation Liquid Filled Transformer

The input primary current is approximately 57% of the rated current making it impossible for the HV overcurrent relay to provide any protection for LV ground faults.

Restricted ground fault protection is therefore strongly recommended to cover winding ground faults and this will be covered in more detail in a later section.

Inter-turn faults

Insulation between turns can break down due to electromagnetic/mechanical forces on the winding causing chafing or cracking. Ingress of moisture into the oil can also be a contributing factor.

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Also an HV power transformer connected to an overhead line transmission system will be subjected to lightning surges sometimes several times rated system voltage. These steep-fronted surges will hit the end windings and may possibly puncture the insulation leading to a short-circuited turn. Very high currents flow in the shorted turn for a relatively small current flowing in the line.

Shorted turn -- Load

++++ Inter-turn faults

Core faults

Heavy fault currents can cause the core laminations to move, chafe and possibly bridge causing eddy currents to flow, which can then generate serious overheating.

Non-Linear Energy Efficient Transformer--Three-phase dry-type transformers, 480 Delta—208Y/120The additional core loss won’t be able to produce any noticeable change in the line currents and thus cannot be detected by any electrical protection system. Power frequency overvoltage not only increases stress on the insulation but also gives an excessive increase in magnetization current. This flux is diverted from the highly saturated laminated core into the core bolts, which normally carry very little flux. These bolts may be rapidly heated to a temperature, which destroys their own insulation, consequently shorting out core laminations.

Fortunately, the intense localized heat, which will damage the winding insulation, will also cause the oil to break down into gas. This gas will rise to the conservator and detected by the Buchholz relay (see later).

Tank faults

Loss of oil through a leak in the tank can cause a reduction of insulation and possibly overheating on normal load due to the loss of effective cooling. Oil sludge can also block cooling ducts and pipes, contributing to overheating, as can the loss of forced cooling pumps and fans generally fitted to the larger transformer.

Differential protection

Differential protection, as its name implies, compares currents entering and leaving the protected zone and operates when the differential current between these currents exceed a pre-determined level.

The type of differential scheme normally applied to a transformer is called the current balance or circulating current scheme.

Relay, Fault: ++++ Differential protection using current balance scheme (external fault conditions)

The CTs are connected in series and the secondary current circulates between them.

The relay is connected across the midpoint where the voltage is theoretically nil, therefore no current passes through the relay, hence no operation for faults outside the protected zone.

Under internal fault conditions (i.e. faults between the CTs) the relay operates, since both the CT secondary currents add up and pass through the relay.

Relay, Fault: ++++ Differential protection and internal fault conditions This protection is also called unit protection, as it only operates for faults on the unit it’s protecting, which is situated between the CTs. The relay therefore can be instantaneous in operation, as it does not have to coordinate with any other relay on the network. This type of protection system can be readily applied to auto-transformers. All current transformer ratios remain the same and the relays are of the high-impedance (voltage-operated) type, instantaneous in operation.

Relay ++++ Differential protection applied to auto-transformers RRR

++++ Auto-transformer - phase and ground fault scheme

Unfortunately, the same parameters cannot be applied to a two-winding transformer. As stated earlier, there are number of factors that need consideration:

• Transformer vector group (i.e. phase shift between HV and LV)

• Mismatch of HV and LV CTs

• Varying currents due to on-load tap changer (OLTC)

• Magnetizing in-rush currents (from one side only)

• The possibility of zero sequence current destabilizing the differential for an external ground fault.

Factor (a) can be overcome by connecting the HV and LV CTs in star/delta respectively (or vice versa) opposite to the vector group connections of the primary windings, so counteracting the effect of the phase shift through the transformer.

The delta connection of CTs provides a path for circulating zero sequence current, thereby stabilizing the protection for an external ground fault as required by factor (e). It’s then necessary to bias the differential relay to overcome the current unbalances caused by factor (b) mismatch of CTs and (c) OLTC. Finally, as the magnetizing current in-rush is predominantly 2nd, harmonic filters are utilized to stabilize the protection for this condition (d). Most transformer differential relays have a bias slope setting of 20%, 30% and 40% as shown. The desired setting is dictated by the operating range of the OLTC, which is responsible for the biggest current unbalance under healthy conditions; e.g. if the OLTC range is +15 to -5% = 20% then the 20% bias setting is selected. Typical connections for a delta-star transformer.

A BC BW P1 P2 A2 A1; a1 a2 P2 P1 S2 S1

++++ Typical connections for a delta-star transformer

Under-load or through-fault conditions, the CT secondary currents circulate, passing through the bias windings to stabilize the relay, whilst only small out-of-balance spill currents will flow through the operate coil, not enough to cause operation. In fact the higher the circulating current the higher will be the spill current required to trip the relay, as can be seen.

Operating current in multiples of relay rating; Bias current in multiples of relay rating: 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20, 40% Bias setting, 30% Bias setting, 20% Bias setting

++++Operating current vs bias current

Operating winding Bias windings

Loads -- Possible fault infeed

Supply end

++++ Biased differential configurations

Restricted ground fault

As demonstrated earlier in this section, a simple overcurrent and ground fault relay won’t provide adequate protection for winding ground faults.

Even with a biased differential relay installed, the biasing desensitizes the relay such that it’s not effective for certain ground faults within the winding. This is especially so if the transformer is resistance or impedance grounded, where the current available on an internal fault is disproportionately low.

In these circumstances, it’s often necessary to add some form of separate ground fault protection. The degree of ground fault protection is very much improved by the application of unit differential or restricted ground fault systems.

++++ A restricted ground fault system

On the HV side, the residual current of the three line CTs is balanced against the output current of the CT in the neutral conductor, making it stable for all faults outside the zone.

For the LV side, ground faults occurring on the delta winding may also result in a level of fault current of less than full load, especially for a mid-winding fault which will only have half the line voltage applied. HV overcurrent relays will therefore not provide adequate protection. A relay connected to monitor residual current will inherently provide restricted ground fault protection since the delta winding cannot supply zero sequence current to the system.

Both windings of a transformer can thus be protected separately with restricted ground fault, thereby providing high-speed protection against ground faults over virtually the whole of the transformer windings, with relatively simple equipment.

The relay used is an instantaneous high-impedance type.

Determination of stability

The stability of a current balance scheme using high-impedance relay depends upon the relay voltage setting being greater than the maximum voltage which can appear across the relay for a given through-fault condition. This maximum voltage can be determined by means of a simple calculation, which makes the following assumptions:

• One current transformer is fully saturated, making its excitation impedance negligible.

• The resistance of the secondary winding of the saturated CT together with lead resistance constitute the only burden in parallel with the relay.

• The remaining CTs maintain their ratio.

RCT1 RCT2 RL1 CT1 CT2 Relay

++++ Basic circuit of high-impedance current balance scheme

Hence, the maximum voltage is given by this Equation …

VIRctR =+


I = CT secondary current corresponding to the maximum steady state through fault current

Rct = Secondary winding resistance of CT

R1 = Largest value of lead resistance between relay and current transformer.

For stability, the voltage setting of the relay must be made equal to or exceed the highest value of V calculated above.

Experience has shown that if this method of setting is adopted the stability of the protection will be very much better than calculated. This is because a CT is normally not continuously saturated and consequently any voltage generated will reduce the voltage appearing across the relay circuit.

Method of establishing the value of stabilizing resistor

To give the required voltage setting the high-impedance relay operating level is adjusted by means of an external series resistor as follows: Let v = operating voltage of relay element Let i = operating current of relay equipment and V = maximum voltage as defined under 'determination of stability' above.

Then the required series resistor setting;

It’s sometimes the practice to limit the value of series resistor to say 1000 ohm, and to increase the operating current of the relay by means of a shunt-connected resistor, in order to obtain larger values of relay operating voltage.

Method of estimating maximum pilot loop resistance for a given relay setting

From Equation 1 above V = I(Rct + R1). Therefore

Primary fault setting

The primary fault setting can now be calculated. In order for this protection scheme to work, it’s necessary to magnetize all current transformers in the scheme plus provide enough current to operate the relay.

Therefore, if; Ir = relay operating current I1, I2, I3, I4 = excitation currents of the CTs at the relay setting voltage N = CT ratio.

Then the primary fault setting = N × (Ir + I1 + I2 + I3 + I4). In some cases, it may be necessary to increase the basic primary fault setting as calculated above. If the required increase is small, the relay setting voltage may be increased (if variable settings are available on the relay), which will have the effect of demanding higher magnetization currents from the CTs I1, I2, etc. Alternatively, or when the required increase is large, connecting a resistor in parallel with the relay will increase the value of Ir.

Current transformer requirements

Class X CTs are preferably required for this type of protection, however experience has shown that most protection type CTs are suitable for use with high-impedance relays, providing the following basic requirements are met:

• The CTs should have identical turns ratio. Where turns error is unavoidable, it may be necessary to increase the fault setting to cater for this.

• To ensure positive operation, the relay should receive a voltage of twice its setting. The knee-point voltage of the CTs should be at least twice the relay setting voltage (Knee-point = 50% increase in mag. Current gives 10% increase in output voltage.)

• CTs should be of the low-reactance type.

Protection against excessively high voltages

As the relay presents very high impedance to the CTs the latter are required to develop an extremely high voltage. In order to contain this within acceptable limits, a voltage dependant resistor (VDR), or metrosil, is normally mounted across the relay to prevent external flashovers, especially in polluted environments.

++++ Protection against excessively high voltages


Calculate the setting of the stabilizing resistor for the following REF protection. The relay is a type CAG14, 1 A, 10-40%, burden 1.0 VA.

RL1 RL2 = 1 ohm RCT1 RCT2 = 3 ohm CT1 CT2 R 30 A

++++ Example for calculation of setting of stabilizing resistor

Secondary fault current = 9000 30A

Relay operating current: Choose 10% tap on CAG14 = 1 A; 10% = 0.1 A

Relay operating voltage: burden 1.0

10V current 0.1

=== Stabilizing voltage:

= ( + 1) = 30(3 + 1) = 120 V VIRctR Voltage across stabilizing resistor: Stabilizing voltage Relay voltage =120 10 = 110 V Voltage across resistor Stabilizing resistance =

Current through resistor

Current transformer must therefore have a minimum knee-point voltage of 2 × 120 = 240 V to ensure positive operation of protection for an internal fault.

HV overcurrent

It’s a common practice to install an IDMTL overcurrent and ground fault relay on the HV side of a transformer. The inherent time delay of the IDMTL element provides back-up for the LV side. High-set instantaneous overcurrent is also recommended on the primary side mainly to give high-speed clearance to HV bushing flashovers. Care must be taken, however, to ensure that these elements don’t pick-up and trip for faults on the LV side as discrimination is important.

For this reason, it’s essential that the HSI element should be of the low-transient over reach type, set approximately to 125% of the maximum through-fault current of the transformer to prevent operation for asymmetrical faults on the secondary side.

HV fault current HSI setting LV fault current Fault current seen from HV side

++++ Fault current as seen from the HV side

This relay therefore looks into, but not through the transformer, protecting parts of the winding, so behaving like unit protection by virtue of its setting.

Current distribution

When grading IDMTL overcurrent relays across a delta-star transformer, it’s necessary to establish the grading margin between the operating time of the star side relay at the phase-to-phase fault level and the operating time of the delta side relay at the three-phase fault level.

This is because, under a star side phase-to-phase fault condition, which represents a fault level of 86% of the three-phase fault level, one-phase of the delta side transformer will carry a current equivalent to the three-phase fault level.

++++ Delta star transformer configuration

0.4 s HV relay LV relay

3f 0.866l ++++Graphical representation of the fault

Buchholz protection

Failure of the winding insulation will result in some form of arcing, which can decompose the oil into hydrogen, acetylene, methane, etc. Localized heating can also precipitate a breakdown of oil into gas.

Severe arcing will cause a rapid release of a large volume of gas as well as oil vapor.

The action can be so violent that the build-up of pressure can cause an oil surge from the tank to the conservator.

The Buchholz relay can detect both gas and oil surges as it’s mounted in the pipe to the conservator.

++++ Mounting of the Buchholz relay

The unit contains two mercury switches. The production of gas in the tank will eventually bubble up the pipe to be trapped in the top of the relay casing, so displacing and lowering the level of the oil. This causes the upper float to tilt and operate the mercury switch to initiate the alarm circuit. A similar operation occurs if a tank leak causes a drop in oil level.

The relay will therefore give an alarm for the following conditions, which are of a low order of urgency:

• Hot spots on the core due to shorted laminations

• Core bolt insulation failure

• Faulty joints

• Inter-turn faults and other incipient faults involving low power

• Loss of oil due to leakage.

The lower switch is calibrated by the manufacturers to operate at a certain oil flow rate (i.e. surge) and is used to trip the transformer HV and LV circuit breakers.

This calibration is important, particularly with large transformers having forced circulation, where starting of the pumps can sometimes cause a rush of oil into the conservator pipe. Obviously operation should not occur for this condition.

When oil is being cleaned and filtered on load as part of routine maintenance, aeration will take place and air will accumulate in the Buchholz relay. It’s therefore recommended that tripping be disconnected, leaving the alarm function only, during this oil treatment process and for about 48 h afterwards. Discretion must then be used when dealing with the alarm signals during this period.

++++ Details of the Bucholtz relay construction

Because of the universal response to faults within the transformer, some of which are difficult to protect by other means, the Buchholz relay is invaluable. Experience has shown that it can be very fast in operation. Speed as fast as 50 ms have been recorded, beating all other protection systems on the transformer in process. Gas sampling facilities are also provided to enable gas to be easily collected for analysis.


A transformer is normally rated to operate continuously at a maximum temperature based on an assumed ambient. No sustained overload is usually permissible for this condition.

At lower ambient it’s often possible to allow short periods of overload but no hard and fast rules apply, regarding the magnitude and duration of the overload.

The only certain factor is that the winding must not overheat to the extent that the insulation is cooked, thereby accelerating ageing. A winding temperature of 98 °C is considered to be the normal maximum working value, beyond which a further rise of 8-10 °C, if sustained, is considered to half the life of the transformer. Oil also deteriorates from the effect of heat. It’s for these reasons that winding and oil temperature alarm and trip devices are fitted to transformers.

Operating Temperature Transformer Oil Life

60 °C 20 years;

70 °C 10 years;

80 °C 5 years;

90 °C 2.5 years; 100 °C 13 months; 110 °C 7 months

Winding temperature is normally measured by using a thermal image technique. A sensing element is placed in a small pocket near the top of the main tank. A small heater fed from a current transformer on the LV side is also mounted in this pocket and this produces a temperature rise similar to that of the main winding, above the general oil temperature.

Dial-type thermometers connected by a capillary tube to a bulb in the oil pocket have been extensively used. These have two contacts fitted which are adjustable to give alarm and trip signals.

Typical settings (e.g. Eskom) normally adopted (unless otherwise recommended by the manufacturers) are as follows: Winding temperature alarm = 100 °C Winding temperature trip = 120 °C Oil temperature alarm = 95 °C Oil temperature trip = 105 °C

On the larger transformers, cooling fans and pumps are employed to control the temperature. In many cases, normal practice seems to be to use IDMTL overcurrent relays for overload protection, CT ratios being chosen on the basis of the transformer full load current.

To use IDMTL overcurrent relays for overload is not a good practice for three reasons:

1. The IEC142 tripping characteristic is not compatible with the thermal characteristic of a power transformer. Incorrect and often unnecessary tripping can occur for light overloads, whilst failure to trip for heavy overloads could shorten the life of the transformer dramatically.

2. If set too fine, there is also the danger of tripping on magnetizing in-rush current of its own or adjacent transformer.

3. It may not coordinate with LV circuit breaker protection for an LV fault, beating it in the process.

Overload protection should be done by oil and winding temperature devices, or relays that have similar tripping characteristics to the thermal time constant of the transformer.

Oil testing and maintenance

There are three important purposes of the oil in a transformer:

1. Good dielectric strength

2. Efficient heat transfer and cooling

3. To preserve the core and assembly

- By filling voids (to eliminate partial discharge)

- By preventing chemical attack of core, copper and insulation by having low gas content and natural resistance to ageing.

It’s therefore vital that the oil is kept in tip-top condition and that regular testing and maintenance be carried out.

Samples should be drawn annually and tested to see if they comply with the following limits: Dielectric strength = 50 kV/minimum Moisture content = 30 ppm maximum Acidity = 0.2 mg KOH/g maximum Interfacial tension = 20 mN/m minimum M.I.N. = 160 minimum

A typical test report is shown ---from which it would be immediately apparent if major problems are imminent and urgent action needs to be taken.

Serial No.: 7324/3 Desig.: TXR3 Customer: Rating: 10 MVA Site: Main Sub Voltage: 33/11 kV

Sampling Date: 93-08-31 Sample: BMT Sample Temp.: 25 °C Tests Done Results Moisture (ppm) 7 Acidity (mg KOH/g) 0.02 Dielectric strength (kV) 73 Interfacial tension (mN/m) MIN (-) Tan Delta at 90 °C (-)

Recommended values: Dielectric strength : 50 kV minimum Moisture content : 30 ppm maximum Acidity : 0.20 mg KOH/g maximum Interfacial tension : 20 mN/m minimum MIN : 160 minimum

+--+ Typical transformer oil test report

However, it’s very important to also conduct a gas analysis on the samples. This analysis of the various constituents can provide some valuable information as to the rate of deterioration (or otherwise) of the transformer insulation.

+--+ illustrates typical readings on an anonymous sample and it’s important to interpret trends rather than absolute levels. There are no hard and fast rules that can be applied and even the oil filtration/purification companies fight shy of interpreting results.

The production rates do, however, assist in drawing conclusions in order to pre-empt major problems occurring in future.

+--+ Typical gas analysis summary

A typical interpretation would be as follows: Interpretation of historical results/trends The high level of Ethane (C2H6) detected in sample no. 5 is a cause for concern.

This is consistent with localized overheating having taken place in the transformer.

The level of Ethylene (41 ppm) is also consistent with this conclusion.


The transformer appears to have had a localized hot spot between samples 4 and 5 but now appears to be fine. If the oil was purified between samples 5 and 6, then the results of sample 6 may not be significant and further samples should be drawn in 6 months time.

Tight control of these procedures and testing can prevent transformer faults occurring, whereas protection relays only operate after the event when the damage has been done.

Gas analysis of samples taken from the Buchholz relay can also prove very illuminating and reveal potential major problems.

Serial No.: 12345/3 Desig.: TXR3 Customer: Rating: 10 MVA Site: Main Sub Voltage: 33/11 kV

Sampling No.: 6 Sample: BMT Sampling Date: 93-08-31 Next Date: 94-08-31 Gas Detected in Samples; Sample Values; Production Rates; Hydrogen (H2) 41 ppm -14.00 ppm/day; Oxygen (O2) 21480 ppm - Nitrogen (N2) 63174 ppm - Carbon Monoxide (CO) 0 ppm -2.00 ppm/day Carbon Dioxide (CO2) 124 ppm -9.00 ppm/day Methane (CH4) 0 ppm 0.0 ppm/day Ethylene (C2H4) 1 ppm - 40.00 ppm/day Ethane (C2H6) 5 ppm -104.0 ppm/day Acetylene (C2H2) 0 ppm - 4.00 ppm/day Total Combustible Gas (TCG) 46 ppm -164.0 ppm/day; Total Gas Content (TGC) 8.7% -

+--+ Typical gas analysis on transformer oil Case 1: Transformer Rating: 250 MVA Voltage: 400/30 kV Circumstances: Buchholz Trip but no Obvious Faults Gas Main Tank Buchholz Oil

Diagnosis: Findings:

Discharges of high energy, arcing, sparking and overheating Flash over from dislocated connection in bushing turret

+--+ Case 1: Transformer rating: 250 MVA; voltage: 400/30 kV

Case 2: Transformer Rating: 11 MVA Voltage: 20/6.6 kV Circumstances: Old Unit in Service for +15 Years Gas Main Tank Conservator

Diagnosis: Findings: Thermal faults of high temperature. Overheated oil and cellulose Interturn flash over between winding layers

+--+ Case 1: Transformer rating: 11 MVA; voltage: 20/6/6 kV

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