Home / Technical Articles / Transformer pre-commissioning tests and after-receipt checks you MUST perform

Healthiness of the transformer

Once oil filling is completed, various pre‐commissioning checks and tests are performed to ensure the healthiness of the transformer (or reactor) prior to its energization. Various electrical tests must be performed and their significance and short description are given below.

Transformer pre-commissioning tests and after-receipt checks you MUST perform
Transformer pre-commissioning tests and after-receipt checks you MUST perform (photo credit: Omicron)

Let’s start with transformer pre-commissioning checks and tests and later on with after-receipt checks:

  1. Pre-commissioning checks and tests:
    1. Core insulation tests
    2. Operational checks on protection system
    3. Insulation resistance (IR) measurement
    4. Capacitance and dissipation factor (tanδ) measurement of bushings
    5. Capacitance and dissipation factor (tanδ) measurement of windings
    6. Turns ratio (voltage ratio) measurement
    7. Vector group and polarity
    8. Winding resistance measurement
    9. Magnetic balance test
    10. Floating neutral point measurement
    11. Measurement of short-circuit impedance
    12. Exciting / Magnetizing current measurement
    13. Vibration measurement of oil‐immersed reactor
    14. Operational check on OLTCs
    15. Stability of differential, REF of transformer / reactor
    16. Tests and checks on bushing current transformers (BCTs)
    17. Frequency response analysis (FRA) measurement
    18. Dissolved gas analysis (DGA) of oil sample
    19. Thermovision infra‐red scanning (IR thermography)
  2. Points to be checked after receipt of a transformer/reactor

1. Pre-commissioning checks and tests

1.1 Core insulation tests

This test is performed to check the insulation between core and ground.

1.2 Operational checks on protection system

Operational checks on:

  1. Cooler bank (pumps and fans),
  2. Breathers (silica gel or drycol),
  3. Temperature gauges (temperature of transformer oil – OTI and the windings temperature – WTI),
  4. Gas actuated relays (Buchholz, PRD, SPR etc.) and
  5. Simulation test of protection system.

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1.3 Insulation resistance (IR) measurement

Test reveals the condition of insulation (i.e. degree of dryness of paper insulation), presence of any foreign contaminants in oil and also any gross defect inside the transformer (e.g. Failure to remove the temporary transportation bracket on the live portion of tap‐changer part).

Insulation resistance tests are performed to determine the insulation resistance from individual windings to earth or between individual windings. Knowledge of the insulation resistance is of value when evaluating the condition of the transformer insulation.

Insulation resistance is commonly measured in megohms, (MΩ).

It should be stated, that variations in insulation resistance can be caused by numerous factors including: design, temperature, dryness, and cleanliness of parts, especially of bushings.

When insulation resistance falls below specified value, it can often be brought back to the required value by cleaning and drying. Insulation resistance varies with the applied voltage. Any measurement comparisons should always be carried out at the same voltage.

Principal measuring circuit for the insulation resistance measurement
Figure 1 – Principal measuring circuit for the insulation resistance measurement

The test is conducted with the help of mega‐ohmmeter. IR is proportional to the leakage current through/over the insulation after capacitive charging and absorption currents become negligible on application of DC voltage.

Insulation resistance shall be measured after the intervals of 15 sec, 60 sec and 600 sec.

The polarization index (PI) is defined as the ratio of IR values measured at the intervals of 600 and 60 seconds respectively. Whereas, the dielectric absorption is the ratio of IR values measured after 60 sec and 15 sec.

IR is normally measured at 5 kV DC or lower test voltage, but the test voltage should not exceed half the rated power‐frequency test voltage of transformer windings.

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1.4 Capacitance and dissipation factor (tanδ) measurement of bushings

Capacitance and dissipation factor Tan δ measurement of bushings shall be done at 10kV with fully automatic test kit so as to have reliable test result.

For 3‐Ph auto‐transformer, short together all 400kV, 220kV and Neutral (isolated from earth) bushings. Also short all 33kV Bushings and earth the same.

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1.5 Capacitance and dissipation factor (tanδ) measurement of windings

The insulation power‐factor test, similar to the insulation resistance test, allows certain conclusions to be drawn concerning the condition of the transformer insulation.

The significance of the power factor figure is still a matter of opinion. Experience has shown, however, that the power factor is helpful in assessing the probable condition of the insulation when good judgment is used.

Measurement of power‐factor values in the factory is useful for comparison with field power‐factor measurements and assessing the probable condition of the insulation.

It has not been feasible to establish standard power‐factor values for the following reasons:

  1. There is little or no relationship between power‐factor and the ability of the Transformer to withstand the
    prescribed dielectric tests.
  2. The variation of power‐factor with temperature is substantial and erratic.
  3. The various liquids and insulation materials used in transformers result in Large variations in insulation
    power factors.

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1.6 Turns ratio (Voltage ratio) measurement

To determine the turns ratio of transformers to identify any abnormality in tap changers/ shorted or open turns etc.

Measurement of turn ratio is based on, applying a phase voltage to one of the windings using a bridge (equipment) and measuring the ratio of the induced voltage at the bridge. The measurements are repeated in all phases and at all tap positions, sequentially.

During measurement, only turn ratio between the winding couples which have the same magnetic flux can be measured, which means the turn ratio between the winding couples which have the parallel vectors in the vector diagram can be measured.

Theoretical turn ratio = HV winding voltage / LV winding voltage

The theoretical no‐load turn ratio of the transformer is adjusted on the equipment by an adjustable transformer. It is changed until a balance occurs on the % error indicator. The value read on this error indicator shows the deviation of the transformer from real turn ratio as %.

% Deviation = 100 x ((Measured TR) ‐ (Designed TR)) / (Designed TR)

Where TR is turn ratio. The % deviation of the turn ratios should be ≤ 0.5 %.

Basic circuit ratio bridge
Figure 2 – Basic circuit ratio bridge

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1.7 Vector Group and Polarity

This test is used to determine the phase relationship and polarity of transformers. Depending on the type of the transformer, the input and output windings of a multi‐phase transformer are connected either as star (Y) or delta(D) or zigzag(Z).

The phase angle between the high voltage and the low voltage windings varies between 0⁰ and 360⁰.

Representing as vectors, the HV winding is represented as 12 (0) hour and the other windings of the connection group are represented by other numbers of the clock in reference to the real or virtual point.

For example, in Dyn 11 connection group the HV winding is delta and the LV winding is star and there is a phase difference of 330⁰ (11×30⁰) between two windings. While the HV end shows 12 (0), the LV end shows 11 o’clock (after 330⁰).

Determining the connection group is valid only in three phase transformers. The high voltage winding is shown first (as reference) and the other windings follow it.

If the vector directions of the connection are correct, the bridge can be balanced.

Also, checking the connection group or polarity is possible by using a voltmeter. Direct current or alternating current can be used for this check. The connections about the alternating current method are detailed in standards.

An example of this method is shown on a vector diagram below.

Connection group representation and measuring
Figure 3 – Connection group representation and measuring

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1.8 Winding resistance measurement

To check for any abnormalities due to loose connections, broken strands and high contact resistance in tap changers.

Winding resistance serves a number of important functions like:

  • Providing a base value to establish load loss.
  • Providing a basis for an indirect method to establish winding temperature and temperature rise within a winding.
  • Inclusion as part of an in‐house quality assurance program, like verifying electric continuity within a
Winding resistance is always defined as the DC‐resistance (active or actual resistance) of a winding in Ohms (Ω).

Principle and methods for resistance measurement

There are basically two different methods for resistance measurement:

  1. So‐called “voltmeter‐ammeter method” and
  2. The bridge method.

“Voltmeter‐ammeter method”

The measurement is carried out using DC current. Simultaneous readings of current and voltage are taken. The resistance is calculated from the readings in accordance with Ohm’s Law. This measurement may be performed using conventional analog (rarely used nowadays) or digital meters.

However, today digital devices such as Data Acquisition Systems (DAS) with direct resistance display are being used more and more.

The measuring circuit is shown in figure 4.

Voltmeter ‐ ammeter method measuring circuit
Figure 4 – Voltmeter ‐ ammeter method measuring circuit


  • RX = Unknown resistance (transformer under test)
  • Rd = Regulating resistor
  • S = Circuit breaker with protective gap
  • B = DC source

Resistance RX is calculated according to Ohm’s Law:

R= U / I

The advantage of this method is the simplicity of the test‐circuit. On the other hand, this method is rather inaccurate and requires simultaneous reading of the two instruments.

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Resistance measurement using a Kelvin (Thomson) Bridge

This measurement is based on the comparison of two voltage drops: namely, the voltage drop across the unknown winding resistance RX, compared to a voltage drop across a known resistance RN (standard resistor), figure 5.

Kelvin (Thomson) Bridge method
Figure 5 – Kelvin (Thomson) Bridge method


  • RX = Unknown resistance (transformer under test)
  • RN = Standard resistor
  • Rdec = Decade resistor
  • RV = Variable resistor
  • G = Galvanometer
  • B = DC source

DC‐current is made to flow through RX and RN and the corresponding voltage drops are measured and compared.

The bridge is balanced by varying the two resistors Rdec and RV, which have relatively high resistance values. A balanced condition is indicated when the galvanometer deflection is zero, at which time the following relationship holds: RX = RN × Rdec / Rv

The influence of contact resistances and the connection cable resistances (even of the connection between RX and RN) can be neglected.

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1.9 Magnetic Balance test

This test is conducted only in three phase transformers to check the imbalance in the magnetic circuit.

In this test, no winding terminal should be grounded. Otherwise results would be erratic and confusing. The test shall be performed before winding resistance measurement. The test voltage shall be limited to maximum power supply voltage available at site.

Evaluation criteria

The voltage induced in the center phase is generally 50% to 90% of the applied voltage on the outer phases. However, when the center phase is excited then the voltage induced in the outer phases is generally 30 to 70% of the applied voltage.

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1.10 Floating neutral point measurement

This test is conducted to ascertain possibility of short circuit in a winding.

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1.11 Measurement of short-circuit impedance

This test is used to detect winding movement that usually occurs due to heavy fault current or mechanical damage during transportation or installation since dispatch from the factory. Ensure the isolation of transformer from high voltage and low voltage side with physical inspection of open condition of the concerned isolators / disconnectors.

In case tertiary is also connected, ensure the isolation of the same prior to commencement of testing. The measurement is performed in single phase mode.

This test is performed for the combination of two winding. The one of the winding is short circuited and voltage is applied to other winding. The voltage and current reading are noted.

The test shall be conducted with variac of 0‐280 V, 10 A, precision RMS voltmeter and ammeter. The conductors used for short‐circuiting one of the transformer windings should have low impedance (less than 1m‐ohm) and short length. The contacts should be clean and tight.

The acceptable criteria should be the measured impedance voltage having agreement to within 3 percent of impedance specified in rating and diagram nameplate of the transformer.

Variation in impedance voltage of more than 3% should be considered significant and further investigated.

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1.12 Exciting / Magnetizing current measurement

This test should be done before DC measurements of winding resistance to reduce the effect of residual magnetism. Magnetizing current readings may be effected by residual magnetism in the core.

Therefore, transformer under test may be demagnetized before commencement of magnetizing current test.

Three‐phase transformers are tested by applying single‐phase 10 kV voltage to one phase (HV terminals) and keeping other winding open circuited and measuring the current at normal, minimum and max. tap positions. Keep the tap position in normal position and keep HV and LV terminals open. Apply single-phase 10kV supply on IV terminals.

Measure phase to phase voltage between the IV terminals and current on each of the IV terminals. The set of reading for current measurement in each of the tap position should be equal. Unequal currents shall indicate possible short circuits in winding.

Results between similar single‐phase units should not vary more than 10 %.

The test values on the outside legs should be within 15 % of each other, and values for the centre leg should not be more than either outside for a three‐phase transformers. Results compared to previous tests made under the same conditions should not vary more than 25%.

If the measured exciting current value is 50 times higher than the value measured during pre-commissioning checks, then there is likelihood of a fault in the winding which needs further analysis. The identical results confirm no damage due to transportation.

The availability of test data of normal condition and faulty condition results help us to analyze the problem in future.

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1.13 Vibration measurement of oil‐immersed reactor

This test is performed in order to measure the vibrations of core / coil assembly in the tank of the reactor. Movement of the core‐coil assembly and shielding structure caused by the time–varying magnetic forces results in vibration of the tank and ancilliary equipment.

These vibrations have detrimental effects such as excessive stress on the core‐coil assembly.

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1.14 Operational check on OLTCs

The aim of this check is to ensure smooth and trouble free operation of OLTC during operation.

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1.15 Stability of differential, REF of transformer / reactor

This test is performed to check the proper operation of Differential & REF protection of Transformer and Reactor by simulating actual conditions.

Any problem in CT connection, wrong cabling, relay setting can be detected by this test.

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1.16 Tests and checks on bushing current transformers (BCTs)

These tests are performed to ascertain the healthiness of bushing current transformer at the time of erection.

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1.17 Frequency response analysis (FRA) measurement

To assess the mechanical integrity of the transformer. Transformers while experiencing severity of short circuit current looses its mechanical property by way of deformation of the winding or core.

During pre‐commissioning this test is required to ascertain that transformer active part has not suffered any severe impact/ jerk during transportation.

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1.18 Dissolved gas analysis (DGA) of oil sample

Oil sample for DGA to be drawn from transformer main tank before commissioning for having a base data and after 24 hours of charging subsequently to ensure no fault gas developed after first charging.

DGA analysis helps the user to identify the reason for gas formation and materials involved and indicate urgency of corrective action to be taken.

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1.19 Thermovision infra‐red scanning (IR thermography)

A thermo vision Camera determines the temperature distribution on the surface of the tank as well as in the vicinity of the Jumper connection to the bushing.

The information obtained is useful in predicting the temperature profile within the inner surface of tank and is likely to provide approximate details of heating mechanism.

Thermovision scanning of transformer to be done at least after 24 hours of loading and repeated after one week.

Thermography inspection of the power transformator
Figure 6 – Thermography inspection of the power transformator

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2. Points to be checked after receipt of transformer / reactor

Following points to be checked after receipt of the transformer / reactor at site:

Check #1

N2 pressure and Dew point to be checked after receipt of transformer at Site. It should be within permissible band (as per graph provided by manufacturer and given below in Figure 7).

Below graph shows variation of pressure v/s temperature of gas-filled unit during transport or storage.

Graph depicting variation of N2 gas pressure w.r.t. temperature
Figure 7 – Graph depicting variation of N2 gas pressure w.r.t. temperature

Example – For 40°C temperature (depending upon the pressure of gas at the time of filling):

  • Minimum pressure of gas can be 0.185 kg/cm2 at point A1
  • Maximum pressure of gas can be 0.32 kg/cm2 at point A2

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Check #2

The data of impact recorder shall be analyzed jointly in association with the manufacturer. In case the impact recorder indicates some serious shocks during shipment, further course of action for internal inspection, if necessary shall be taken jointly.

Impact recorder should be detached from the transformer/ reactor preferably when the main unit has been placed on its foundation.

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Check #3

Oil samples should be taken from oil drums / tanker received at site and sent to dedicated lab for oil parameter testing. The copy of test certificate of routine testing at oil refinery should be available at site for comparison of test results.

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Check #4

Unpacking and inspection of accessories to be carried out taking all precautions so that the tools used for opening do not cause damage to the contents. Fragile instruments like oil level gauge, temperature indicators, etc. are to be inspected for breakage or other damages.

Any damaged or missing components should be reported to equipment manufacturer, so that the same can be investigated or shortage made up as per the terms/ conditions of the contract.

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Check #5

Core Insulation Test shall be carried out to check insulation between core and ground. (not applicable for air core reactors).

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Check #6

After receiving the accessories at site same should be inspected and kept ready for immediate erection:

If erection work can not start immediately due to some reasons, then accessories should be repacked into their own crates properly and packing list should be retained.

All packings should be kept above ground by suitable supports so as to allow free air flow underneath. The storage space area should be such that it is accessible for inspection; water does not collect on or around the area and handling/transport would be easy.

Proper drainage arrangement in storage areas to be ensured so that in no situation, any component get submerged in water due to rain, flooding etc..

Immediately after the receipt of main transformer unit and also the accessories, same should be inspected and if found satisfactory, the unit should be erected completely and filled with dry transformer oil as per the instruction.

It is preferable to store the main unit on its own location/foundation. If the foundation is not likely to be ready for more than three (3) months, then suitable action plan has to be taken from the manufacturer regarding proper storage of the main unit.

If the transformer / reactor is to be stored up to three months after arrival at site, it can be stored with N2 filled condition. N2 pressure to be monitored on daily basis so that chances of exposure of active part atmosphere are avoided.

In case of drop in pressure, dew point of N2 has to be measured to check the dryness of the transformer/ reactor.

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Check #7

During erection, the exposure of active part of transformers should be minimized. Further either dry air generator should be running all the time or dry air cylinders may be used to minimize ingress of moisture.

For oil filled units whenever oil is drained out below the inspection covers, job will be treated as exposed.

Other exposure activities are as below:

  1. Bushing erections
  2. Jumper connections of Bushings
  3. Fixing bushing turrets on cover
  4. Fixing bushing turrets on side
  5. Core insulation checking
  6. Buchholz relay pipe work fixing on cover.
  7. Gas release pipes/equaliser pipe fixing.
  8. Entering inside the tank for connections/inspection etc.
For oil filled units depending upon the level up to which the oil is drained decides the exposure time. All such exposure time should be recorded in a log sheet to decide the oil processing (drying) and oil filling of transformer.

For transformers with a gas pressure of 2.5‐ 3 PSI, the acceptable limits of dew point shall be as under:

Table 1 ‐ Variation of dew point of N2 gas filled in transformer tank temperature

Temperature of insulation in °FMaximum permissible dew point in °FTemperature of insulation in °CMaximum permissible dew point in °C

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Reference // Power transformer testing by MTEKPRO

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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 fascilities. Professional in AutoCAD programming. Present on


    Dec 28, 2018

    Excellent article, simply baffled by the contents. can you explain the actual method adopted to identify the vector group of the transformers.

    • Madhav
      Jan 04, 2019

      There is a certain procedure and criteria for evaluation for vector group identification.. e.g. here in our country most of the dist, tfs are having vector group Dyn11.. for identification of this vector group normally the following checks are performed-

      connect (short) the HV R terminal (1U) and LV R terminal (2U) together…
      apply some voltage from HV side (say 400V) and then verify the following conditions:

      Voltage between the terminals ( HV terminal: 1U,1V 1W and LV terminal: 2U, 2V, 2W)
      1) 1V2W = 1V2V
      2) 1U2N+1V2N = 1U1V and
      3) 1W2W < 1W2V

      Hope this will help you,


  2. jayasree
    Dec 27, 2018

    very good article ; useful and informative and updated

    Dec 27, 2018

    very good guide for new Engineers

  4. Dr Wilson Alli
    Dec 26, 2018

    I love your works. How may I get the compendium?

    Dec 26, 2018

    Perfect article. I am going to use it as guideline

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