Introduction
Transformer is the most important unit in an electrical distribution network. All transformers are subjected to thorough tests at the manufacturer’s

 

1.0             SCOPE

 

The idea of this document is to give guidelines to the Maintenance personnel of steel plants on carrying out proper maintenance in oil filled power transformer of high voltage and extra high voltage grades.

 

In this document, various maintenance schedules to be adhered to (hourly, daily, monthly, half yearly, yearly, once in five years and once in ten years) are given to enable the maintenance personnel to carry out the maintenance and inspection jobs and to ensure long life to equipment, safety to men and material and also to achieve trouble-free service and un-interrupted power supply to the plant. Though most of the maintenance activities and tests can be conducted in-house, we can make use of Central Power Research Institute and National Power Grid Corporation, etc. for certain tests like dissolved gas analysis and furan analysis.

 

1.1       Reference

 

Sl No.

INDIAN STANDARD No.

TITLE

1.            

10028-Part 3:1981

Code of practice for selection, installation and maintenance of transformers : Part 3 Maintenance (superseding IS:1886)

2.            

1866.2000

Method for determination of electric strength of insulating oils (First Revision)

3.            

335:1993

New insulating oils (Fourth Revision)

4.            

2362:1993

Determination of water by Karl Fisher Method –Test Method (Second Revision)

5.            

6103:1971

Method of tests for specific resistance (resistivity) of electrical insulting liquids

6.            

1866:2000

Code of practice for electrical maintenance and supervision of mineral insulating oil in equipment (Third Revision)

7.            

1448(p21):1992

Petroleum and its products – methods of test – Part 21 : Flash point (Closed) by Pensky Martens Apparatus (Second Revision)

8.            

6104:1971

Method of test for interfacial tension of oil against water by the ring method

9.            

6262:1972

Method of test for power factor and dielectric constant of electrical insulating liquids

 

 

2.0             GENERAL

 

As is generally known, a transformer consists essentially of the magnetic core built-up of insulated silicon steel lamination upon which are wound two distinct sets of coils suitably located with respect to each other and termed as primary and secondary windings.  Such a combination may be used to step up or step down the voltage. 

 

The techniques used in the design and construction of high voltage transformers vary from supplier to supplier.  The active parts of a transformer consist of core and windings.

 

2.1       CORE  

 

Core is made from lamination of cold rolled grain oriented silicon steel.  The specific loss at operating flux densities in silicon steel is very low. 

 

2.2       WINDINGS

 

Paper insulated copper conductor is used for windings.  The conductors are transposed at regular intervals for ensuring equal flux linkage and current distribution.

 

2.3   COOLING 

 

Core and windings are immersed in an oil filled tank.  Normally, oil flows through winding and enter cooler or radiator by thermosyphonic effect. 

 

Depending upon the rating, the transformer employs ONAN, ONAF, OFAF and  OFWF types of cooling.

 

ONAN - Oil Natural Air Natural

ONAF - Oil Natural Air Forced

OFAF - Oil Forced Air Forced 

OFWF - Oil Forced Water Forced

 

2.4   TANK AND COVER 

 

Steel plates are used for fabricating transformer tanks and covers.  They are designed to withstand full vacuum and a positive pressure of            0.3 kg/cm2  above the normal oil head.

 

2.5   CONSERVATOR 

 

Conservator takes care of the expansion and contraction of transformer oil, which takes place due to loading and releasing of load.  Modern transformers are provided with separate air shell in the conservator which prevents direct air contact with the transformer oil.

 

A separate conservator is provided for the on-load top changer diverter switch.  Magnetic oil level gauges are provided in the conservator tanks which can give alarm to the operators and isolate the transformer in the event of oil level falling below a preset value.

 

2.6   PRESSURE RELIEF DEVICE

 

A pressure relief device is provided with an alarm and trip contacts.  When excessive pressure is built inside the transformer in the event of severe fault, the pressure relief device releases the excess pressure.

 

For smaller transformers, an explosion vent is provided with a lighter diaphragm which breaks in the event of increasing internal pressure.

 

2.7   BUCHHOLZ RELAY

 

This gas and oil actuated relay is provided in the oil pipe which connects the conservator and the main tank.  For any internal fault inside the transformer, this relay is actuated.   This relay operates on the well-known fact that every type of electric fault in an oil-filled transformer gives rise to gas.  This gas is collected in the relay to actuate the alarm and trip contacts.

 

2.8   SILICA GEL BREATHER

 

Expansion and contraction of oil due to loading causes breathing.  External air gets in during the time of contraction.  Silica gel absorbs the moisture in the air and prevents moisture entry into the oil.

 

2.9    TEMPERATURE INDICATORS

 

For continuous measurement of oil and winding temperatures, separate meters are used.  These meters have alarm and trip contacts. 

2.10    BUSHINGS

 

High voltage connections from the windings pass to the terminal bushings.  These bushings are hermitically sealed and filled with oil for EHV transformers.  This oil does not communicate with the main transformer oil.   A separate oil level gauge is provided for monitoring the oil level in the bushings.

 

2.11    TAP CHANGER

 

There are two types of tap changers viz., on load and off load.  In on load tap changer, tap position changes, when the transformer is energized either through manual mode or auto mode. The OLTC diverter switch has separate oil which needs periodical changing as some amount of arcing takes place during tap changing operations. This has a separate conservator and a Buchholz relay.

 

2.12PROTECTIONS FOR TRANSFORMER

 

The following protections are provided normally for a transformer.

(i)           Over current protection

(ii)         Restricted Earth fault protection

(iii)       Over voltage protection alarm

(iv)       Over fluxing ( generator transformers )

(v)         Surge protection

(vi)       Differential protection ( above 5 MVA )

(vii)     Oil temperature high protection

(viii)   Winding temperature high protection

(ix)       Oil level low protection

(x)         Buchholz protection

(xi)       Pressure relief device

 

The relays checking and calibration procedures are not covered in this document.

 

 

3                MAINTENANCE

 

It is essential to carry out regular and careful inspection on the transformer and associated components/equipment and carry out maintenance activities to provide long life to the equipment and achieve trouble-free service.

 

IN ORDER TO CARRY OUT THE NECESSARY INSPECTION AND MAINTENANCE WORKS, NECESSARY SAFETY PROCEDURES SUCH AS LINE CLEARANCE/EQUIPMENT SHUTDOWN ETC., WILL BE STRICTLY ADHERED TO, WHEREVER NECESSARY.

The frequency of inspection depends on climate, environment, load conditions and also the age of the transformer.  The inspection cum maintenance schedule starts with every hour and continues as given below.

 

3.1       HOURLY

 

The following parameters are to be checked every hour and recorded.  If the observed value exceeds the value given by the supplier, immediate remedial action should be taken.

           

(i)                 winding temperature

(ii)               oil temperature

(iii)             load current

(iv)             terminal voltage

 

Normally, maximum allowed winding temperature is 55º C above ambient and oil temperature is 45º C above ambient (actual allowed value may vary from supplier to supplier).

 

3.2       DAILY

 

(i)                 Oil level in main conservator

(ii)               Oil level in OLTC

(iii)             Oil level in bushing

(iv)             Leakage of water into cooler (OFWF)

(v)               Water temperature  (OFWF)

(vi)             Water flow (OFWF)

(vii)           Colour of silica gel

 

3.3             QUARTERLY CHECKING/ REPLACEMENT

 

Reconditioning of  silica gel breather.

Checking of water cooler functioning

Checking of cooling fans functioning

Gear oil for tap changer mechanism

Checking of cooling pumps and motor functioning

 

3.4    HALF YEARLY

 

(i)                 Inspection of all gaskets and joints

 

 

                                

 

 

 

3.5      ANNUALLY

 

(i)                 Protective relays, alarms, meters and circuits to be checked and calibrated

(ii)               IR value and Polarisation Index

(iii)             Tan delta and capacitance of bushings 

(iv)             BDV of transformer oil.

(v)               Oil resistivity

(vi)             Power factor of oil

(vii)           Interfacial tension of oil

(viii)         Acidity and sludge of oil

(ix)             Flash point of oil

(x)               Water content of oil

(xi)             Dissolved gas analysis

(xii)           Replacing of OLTC oil

(xiii)         Thermo vision scanning

(xiv)         Earthing  measurements

(xv)           Tan delta and capacitance of  winding

 

3.6      ONCE IN FIVE YEARS

 

(i)                 Furan analysis  (Once in a year after the first 5 years)

(ii)               Overhauling of OLTC diverter switch (once in 5 years or after completion of 50,000 operations whichever is earlier)

 

3.7       ONCE IN TEN YEARS

 

            Overhaul, inspection including lifting of core and winding.

 

 

4.0       MAINTENANCE GUIDELINES

 

4.1       BDV OF TRANSFORMER OIL (As per IS 6792:1992)

 

The oil sample is subjected to a steadily increasing alternating voltage until breakdown occurs in a BDV test kit.  The breakdown voltage is the voltage reached at the time of the first spark appears between the electrodes.  The test is carried out six times on the same cell filling and the electric strength of the oil is the arithmetic means of the six results obtained.  The electrodes are mounted on a horizontal axis with a test spacing of   2.5 mm.  The value should be

 

 

1

 

 

Electric Strength (BDV)

IS 1866:2000

 

50 KV (Min)

 

40 KV (Min)

30 KV (Min)

 

Above 170 KV  to  420 KV

 

Above  72.5KV to 170KV

Upto   72.5KV

 

 

4.1.1   SPECIFICATION FOR UNINHIBITED MINERAL INSULATING OIL-NEW/ UNUSED BEFORE FILLING IN TRANSFORMER/ SWITCHGEAR

 

 

Sl.No.

 

 

CHARACTERISTICS/PROPERTY

 

 

IS 335:1983

 

 

1

 

 

2

3

4

5

6

7

a

b

8

9

 

a

b

10

 

11

a

b

12

a

b

13

 

a

i

Ii

b

    c

d

14

 

15a

b

16

17

18

 

 

 

 

Appearance

 

 

Density at 29.5º C, Max.

Kinematic Viscosity at 27º C, Max.

Interfacial Tension (IFT) 29.5º C, Min.

Flash point, Pensky Martin (Closed), Min.

Pour point, Max.

Acidity, Neutralisatin Value

Total Acidity, Max.

Inorganic acidity/Alkalinity

Corrosive Sulphur

Di-electric Strength (Breakdown Voltage)

Min.

New unfiltered oil

After filtration

Dielectric Dissipation Factor (Tan δ)

DDF at 90º C, Max.

Specific Resistance (resistivity)

At 90º C, Min.

At 27º C, Min.

Oxidation Stability

Neutralisation value after oxidation, Max.

Total sludge after oxidation, Max.

Ageing Characteristics after accelerated ageing (Open Breaker method with copper catalyst)

Specific Resistance (resistivity)

At 27º C, Min.

At 90º C, Min.

DDF at 90º C, Max.

Total Acidity, Max.

Total Sludge Value, Max. % by weight

Presence of Oxidation Inhibitor   

 

Water content-New unfiltered oil

After filtration

PCB Content

SK Value

Dissolved Gas Analysis (DGA)

 

 

 

Clear & transparent Free from suspended matter or sediments

 

0.89 g/cm3

27 cst

0.04 N/m

140º C

-6º C

 

0.03 mg KOH/g

NIL

Non-corrosive

 

 

30 KV, rms

60 KV, rms

0.002

 

 

35 x 1012 ohm -cm

1500 x 1012 ohm-cm

 

0.40 mg KOH/gm

0.10% by weight

 

 

 

2.5 x  1012 ohm -cm

0.2 x  1012 ohm -cm

0.2

0.05

0.05

Max. 0.05% treated as absence of oxidative inhibitor

50 ppm

15 ppm

< 2 ppm

4 to 8%

Not applicable

 

 

 

 

 

 

4.1.2       RECOMMENDED LIMITS OF UN USED MINERAL OIL IN NEW POWER  TRANSFORMERS AS PER IS 1866:2000

 

 

Sl.No

Property

Power transformer upto 72.5 KV

Power transformer above 72.5 KV To 170 KV

Power transformer above 170 Kv

 

01

 

BDV

 

30 KV

 

40 KV

50 KV

 

02

 

Flash point

 

140° C

 

140° C

140° C

 

03

 

Pour point

 

- 6 ° C

 

- 6 ° C

- 6 ° C

 

04

 

Water content

20 ppm

15 ppm

 

10 ppm

 

 

05

 

Neutralisation  value    ( mg KOH/ g)

0.03

0.03

0.03

 

06

 

Di – electric dissipation factor at 90° C

0.015

0.015

0.010

 

 

5.0       MEASUREMENT OF INSULATION RESISTANCE

 

5.1       RECOMMENDED VALUES

 

Related Voltage Class

of Winding

Min. IR value at

one minute

 

11 KV

 

300 Meg. Ohm

33 KV

400 Meg. Ohm

66 KV and above

500 Meg. Ohm

 

5.2       MEASUREMENT OF POLARISATION INDEX

 

If moisture is present in a system, the leakage current increases at a faster rate than the absorption current and the mega ohm readings will not increase with time as fast with insulation in poor condition as with insulation in good condition.  This results in a lower PI.

 

            PI = 10 minutes IR value/1 minute IR value

Polarisation Index

Insulation Co-ordination

 

          < 1

 

Dangerous

          1.0 to 1.1

Poor

Above 1.1 to 1.25

Questionable

Above 1.25 to 2.0

Fair

Above 2

Good

 

 

6.0       DRYING OUT OF TRANSFORMER

 

Deterioration of insulation resistance value of transformer is mainly due to ingress of moisture into the windings and insulating materials.   In order to improve the insulation resistance at site, following methods are available:

 

(i)           Hot Oil Spraying:  In this method about 7% of quantity of oil is heated up to 90-95º C separately and the hot oil is sprayed on to core and windings by means of nozzles in the form of fine spray and simultaneously the transformer is subjected to a high degree of vacuum say less than 5 m bar.  The hot oil is collected at the bottom sent through a filter and reheated and sprayed.  This process removes moisture from the core and windings.  The oil used for spraying should be discarded.

 

(ii)         Flushing Method:   In this method, the transformer is put under hot oil circulation up to 60º C.  After reaching steady temperature, the entire oil is drained quickly into a separate tank. Immediately after draining the oil, the transformer is subjected to a vacuum as per the guidelines of the manufacturer for 12 hours.  During this period of application of vacuum, the transformer oil drained can be filtered to improve the quality.  After 12 hours of vacuuming of the transformer, break the vacuum by means of dry nitrogen.  Fill the transformer with filtered oil under vacuum. Now the oil in the transformer can be again circulated to raise the temperature of oil to 60º C.   Again drain the oil, apply vacuum and repeat the process till you get a good IR value. 

 

Precautions 

 

The diverter switch tank and the main tank should be inter-connected before the above works to equalize the pressure.  Otherwise the diverter switch tank may be damaged when the vacuum is applied.

 

 

7.0       BUCHHOLZ RELAY FUNCTIONAL TEST

 

Tools and materials required:

 

Cycle pump or Nitrogen cylinder with 4 kg/cm2 pressure and connecting tubes.

 

Procedure:

 

Ø      Transformer shall be isolated.

Ø      Connect Nitrogen cylinder or cycle pump to the top petcock of Buchholz relay

Ø      Open the other petcock

Ø      Allow gas to enter the relay

Ø      Check and confirm alarm signal is received

Ø      Close petcock on gas supply side and release all gases trapped in relay casing

Ø      Increase the gas pressure to approx. 2 kg/cm

Ø      Open the test petcock and allow full surge of gas to enter the relay casing

Ø      Check and confirm in control room that the Trip signal has been received

Ø      Close Buchholz relay petcocks and normalize

 

7.1       BUCHHOLZ GAS ANALYSIS

 

This is to be done only when the transformer has tripped on account of Buchholz fault or Buchholz alarm has been initiated. 

 

The following procedure should be adopted for testing of gas accumulated in Buchholz relay of power transformers.-

 

(i)                 Switch off the transformer when the Buchholz relay alarm rings, indicating the development of an internal fault in the transformer.

 

(ii)               Through the lateral sight hole of the Buchholz relay, the colour and quantity of the gas may be determined.

 

(iii)             Collect a portion of the gas in the test tube and apply a lighted match stick to the test tube to test the combustibility of the gas.

 

If gas is not combustible, it is mere air.

 

(iv)             Then proceed to carry out the chemical test with a simple gas tester as follows:

 

The gas tester consists of two glass tubes containing two different silver nitrate solutions which through passage of decomposed gases form two distinguishable precipitates.  The tubes must be assembled as indicated in the sketch and tube 1 should be filled with solution prepared by dissolving 5 grams of silver nitrate (Ag NO3) in 100 cc of distilled water.

 

Tube 2 should be filled with solution prepared by dissolving five grams of silver nitrate (Ag NO3) in 100 cc of watery ammonia solution.

 

Use of the gas tester is quite simple.  Each of the two glass tubes should be filled with corresponding solutions upto the marks.  They should be closed by corks fitted with the connecting tubes.  Then the gas tester should be screwed on to the test cock of the Buchholz relay.  After opening the test cock the collected gas would flow through the solution which would indicate the nature of the fault.

 

If the gas causes a white precipitate in tube 1 which turns brown under the influence of light, it means the oil has decomposed.  Probably a flashover has occurred between bare conductors or between one bare conductor and an earthed part of the transformer.

 

If the gas causes a dark brown precipitate in the solution in tube 2 it means that solid insulating material like wood, paper, cotton, etc., had decomposed producing carbon monoxide (CO).  In this case a leakage in the winding causing an internal short has occurred.

 

If there is no sedimentation at all the gas is mere air.

 

 

 

 

 

 

 

 

 

 

 


8.0       TAN DELTA AND CAPACITANCE MEASUREMENT OF TRANSFORMER BUSHING

 

These measurements of bushing provide an indication of the quality and soundness of the insulation of the bushing.

 

For getting accurate results of Tan Delta and capacitance for oil filled bushing without removing the bushing from the transformer, a suitable test kit of ungrounded specimen test shall be used.  Portable standard kit is to be used and the measuring instruction of the meter manufacture is to be followed.  The value obtained after the test is to be compared with the value given by the supplier or the value obtained at the time of commissioning.  An increase of dissipation factor (Tan Delta) by a marked increase in capacitance indicates excessive moisture in the insulation.  Increase of Tan Delta value alone may be caused by thermal deterioration or by contamination.  Maximum value Tan Delta for Class “A” insulation (paper insulation, oil impregnated) is 0.007 at 20ºC.  Rate of rise of Tan Delta per year of service is 0.001 (max) and the rate of rise of capacitance value per year of service is +1% (max). Rate of change of Tan Delta and capacitance is very important.  Capacitance value may vary from -5% to +10%.  If Tan Delta is not measured at 20ºC, the following correction factor is to be applied.

 

Ambient Temperature (in ºC)

Correction Factor

 

15

20

25

30

35

40

45

50

55

60

 

 

0.90

1.00

1.12

1.25

1.40

1.55

1.75

1.95

2.08

2.42

 

 

8.1       Capacitance and Tan Delta Measurement of Winding Insulation of Transformer

 

            The above measurement is carried out to ascertain the general condition of the ground and inter – winding insulation of transformers. Portable capacitance and tan delta bridge from any reputed manufacturer may be used for carrying out this test. All safety instructions as per utility practice and isolation required may be followed before the commencement of this test.

 

Following precautions need to be taken:

 

1.   Never connect the test set to energized equipment.

2.      The ground cable must be connected first and removed last.

3.      Heart patients should not use this equipment.

4.      The ground   terminal of the input supply card (green lead) must be connected to the protective ground (earth) terminal of the line power source.

5.      Keep the high voltage plugs free from moisture, dust during installation and operation.

6.      Adequate clearance (Min 1 foot i.e. 30 cms) are maintained between energized conductor and ground to prevent any arc over.

7.      It should be ensured that test specimen is de –energised and grounded before making any further connection and no person may come in contact with HV output terminal or any material energized by the output.

 

Testing Procedure

 

For the purpose of this test, the voltage rating of each winding under test must be considered and test voltage selected accordingly. If neutral bushings are involved, there voltage rating must also be considered in selecting the test voltage. Measurement should be made between in each inter winding combination (or set of 3 phase winding in a 3 phase transformer) with all other windings grounded to tank or ground all the other windings guarded. In the case of 2 winding transformer measurement should be made between each winding and ground with the remaining winding grounded. For 3 winding transformer measurement should be made between each winding and ground with 1 remaining winding guarded and second remaining winding grounded.  Finally measurement should be made between all winding connected together and grounded tank.

 

 

9.0       DISSOLVED GAS ANALYSIS

 

Dissolved gas analysis is a powerful diagnostic technique for detecting incipient faults in oil filled transformers long before they develop into major faults.  The transformer in operation is subject to various stresses like thermal and electrical resulting in liberation of gases from the hydrocarbon mineral oil, which is used as an insulant and coolant.  The components of solid insulation also take part in the formation of gases, which are dissolved in the oil.  An assessment of these gases, both qualitatively and quantitatively, would help in diagnosing the internal faults.

 

9.1       PERMISSIBLE LIMITS OF DISSOLVED GASES IN A HEALTHY TRANSFORMER

 

Gas

Less than 4 years in service

4-10 years in service

More than 10 years in service

 

Hydrogen (H2)

 

100/150 ppm

 

200/300 ppm

 

200/300 ppm

Methane (CH4)

50/70 ppm

100/150 ppm

200/300 ppm

Acetylene(C2H2)

20/30 ppm

30/50 ppm

100/150 ppm

Ethylene (C2H4)

100/150 ppm

150/200 ppm

200/400 ppm

Ethane (C2H6)

30/50 ppm

100/150 ppm

800/1000 ppm

Carbon Monoxide (CO)

 

200/300 ppm

 

400/500 ppm

 

600/700 ppm

Carbon-di-oxide (CO2)

3000/3500 ppm

4000/5000 ppm

9000/12000 ppm

 

 

·        DGA is done in CPRI, Bangalore and their recommendations are furnished to their customers, based on the actual contents of the gases mentioned above for remedial action.

 

9.2       GAS ANALYSIS AND CORRESPONDING FAULTS

 

 

Gases

 

Possible faults

 

Findings

 

All the gases and Acetylene present in large amounts.

 

High energy electrical arcing 700º C and above.

 

Same as above with metal discoloration.  Arcing may have caused a thermal fault.

 

H2, CO, CH4, C2H6 and C2H4

 

Thermal fault between 300º C and 700º C.

 

Paper insulation destroyed.  Oil heavily carbonized.

H2, CO

 

Thermal faults less than    300º  C in an area close to paper insulation (Paper is being heated).

 

Discoloration of paper insulation. Overloading or cooling problem. Bad connections.  Stray current path and/or stray magnetic flux.

H2, CH4, C2H6, C2H4and C2H2  present in large amounts.  If   C2H2 is being generated, it indicates continuance of arcing CO will be present if paper is being heated.

 

High energy discharges (arcing)

 

Metal fusion, (poor contacts in tap changer or lead connections). Weakened insulation, from ageing and electrical stress.  Carbonised oil.  Paper overhauling/ destruction if it is in the arc path.

 

H2, CH4 (CO if discharges involve paper insulation).

Possible trace of

C2H6

 

Low energy discharges (sparking)

 

Pinhole puncture in paper insulation with carbon and carbon tracking.  Possible carbon particles in oil.  Loose grounding of metal objects.

 

H2 possible traces of CH4 and C2H6 possible CO.

 

Partial discharge (Corona)

 

Weakened insulation from ageing and electrical stress.

 

 

9.3       DISSOLVED GAS ANALYSIS USING GAS RATIOS 

 

            (Ratios are to be calculated only if the concentrations of both the gases are above the detection levels)

 

 

Sl.No.

 

Ratio & Value

 

Remarks

 

1

 

 

C2H2 

 

 

More than 1

 

 

Indicates fault

C2H6

 

 

2

 

 

H2 

 

 

More than 10

 

 

Indicates problem

CH4

 

 

3

 

 

C2H4

 

More than 1

 

Thermal fault

C2H6

 

 

4

 

 

CO2

 

More than 10

 

Thermal overheating

CO

 

 

5

 

 

C2H2 

 

More than 2

 

Possibly tap changer oil leaks into the main oil

  H2

 

 

 

 

10.0    FURAN ANALYSIS

 

This is a powerful diagnostic test carried out to detect the healthy conditions of the solid insulating materials used in a transformer.  Furans are a family of organic compounds, which are formed by degradation of paper insulation.  Quality of paper, moisture and oxidation can cause furan formation.  The following table indicates the condition of the transformer in the presence of furan.

 

Total Furan (ppb)

Condition of the transformer

0-100

Normal

101-250

Questionable

251-1000

Deteriorated

1001-2500

Low reliability

> 2500

Rewind/replace solid insulation

 

The above test is done at CPRI.

 

 

11.0THERMO VISION SCANNING

 

Thermo Vision Scanning is one of the most valuable diagnostic tools used for predictive maintenance. Thermo vision scanning is used for electrical inspections. When excess heat is generated in an equipment thermo vision scanning can locate the spot of excess heat and action in time can avoid break downs and failures. Since thermo vision scanning is done with a non – contact type thermo vision camera, equipment need not be isolated form power supply and load conditions. Portable infrared imaging systems are available which convert the thermal images to visible pictures for quantitative temperature analysis.

 

Using this, transformer on load can be scanned and the transformers subject to higher temperatures are identified.

 

 

12.0    AUXILIARY EQUIPMENT

 

Cooling equipment, fans, motors, pumps, control wiring etc., should be checked once in a year.  It is also necessary to check both the LT and HT side terminations once in a year.

 

 

 


works before despatch to the destination of erection.Due to limitations in transport, large capacity transformers are dis-assembled into various components before dispatch. At site, the transformers are re-assembled with the various components like bushings, coolers, conservator etc. and then the internal body is dried out to remove the surface moisture sticking to the paper insulation during exposure at site. As erection of transformers involve assembly of various components, pre-test inspection of transformers have greater importance than other parts of an electrical system. The following paragraphs explain the pre-test inspections/pre-commission checks and the pre-commission tests to be conducted on power transformers prior to energisation of the unit.
Recording the salient parameters
As the service life of a transformer is expected to cover very many years, it is necessary to record the salient parameters of the transformer for future reference. Rated capacity, rated voltage ratio,connection, make, maker’s serial number, year of manufacture, date of completion of erection,insulation dry out details at site etc. may be documented in a register as permanent record. It is also necessary to record the serial number, rating and make of various components like bushings, tap changer, tap changer control cubicle, cooler control cubicle, cooling fans, oil pumps, Buchholtz relay,temperature indicators, heat exchangers, oil flow meter, water flow meter, pressure gauges, oil level gauge etc. For easy reference, the details of the main body and various components may be recorded in separate pages of a register. This register will serve as a record of the service of the transformer.Details of replacement of components may also be recorded in the same register.
Pre-commission checks
Before commencing the pre-commission tests, it is necessary to visually inspect various parts,components and accessories of the transformer and also to conduct operational check for various protective devices. Check lists may be followed for the visual inspection and the operational checks so that the pre-commission checks are conducted in a systematic manner and also that no check/test is omitted. Model check lists for General checks and Functional checks are given at the end of thischapter in Appendix 2.1 and 2.2 respectively.
General checks
(i) General arrangement
The General arrangement of the electrical installation shall be checked for concurrence with the
scheme approved by the Department of Electrical Inspectorate. Special emphasis may be given to the
following:
· size of cables
· size of bus bars
· size of bus trunking
· size of earthing conductors
· adequacy of various clearances
· spacing between supports
· ventilation
· oil drain facilities
· fire protection walls
· fire fighting arrangements
(ii) Terminations
The transformer terminal connections may be checked for the following:
· flexibility and area of cross section of flexible connections at bushings
· clearances of live jumper connections from transformer tank and accessories
· socket size
· perfection of crimpings
· tinning of contact surfaces to prevent bimetalic action
· clearances inside cable end box
· clearances of bus bar trunking
· conformity of cable end box with the relevant IP( Ingress Protection) classification
· correctness of cable glanding and adequacy of cable gland earthing or pig tail
· support of cables at terminations and unsupported lengths
(iii) Perfection of connections
Connections to the following shall be checked for proper surface contact, seating and tightness.
· to bushings
· to the tap changer
· to earth leads
· to control and protective cables
· to thermometers
(iv) Earthing

 

Check the size of earthing conductors, tinning of contact surfaces, area of contact and seating,effectiveness of bolting, socketing, riveting, welding etc.for the earthing of the following:

· Duplicate earthing for neutral and body

· Main tank and top cover
· Fan motors
· Pumps
· On Load Tap Changer (OLTC) chamber
· Tap changer driving gear
· Divertor switch
· Cable glands/termination
· Marshalling box
(v) Control cable connections
Check the control cable connections between the following
· transformer accessories and marshalling box
· marshalling box and sub-station panel
· tap changer control cubicle and sub-station panel
(vi) Radiator
Check the radiator for release of air and position of valves. The valves shall be in open position.
(vii) Main conservator and OLTC conservator
Check the oil level in the main conservator and OLTC conservator . The conservator shut off valve in the Buchholtz relay pipe line shall be in open position.
(viii) Bushings
Check the oil level in the bushings if sealed bushings are used. Release air from bushings if air release plugs are provided.
(ix) Breather
Check the oil level in the oil seal of the breather. Check the colour of the silica gel in the breather .
(x) Cooler units, fans and pumps
Check fans and pumps for proper mounting. The number of fans and their position on the radiators shall be in conformity with the general arrangement drawings.
· Check the direction of rotation of cooling fans and pumps
· Check the direction of oil flow
· Check flow of water in heat -exchangers
· Measure the Insulation Resistance (IR) of fans and pumps
· Check the settings for operation of fan motors and oil pumps
· Check the cooler unit for correct indication of oil flow and setting of the thermometer
(xi) Winding Temperature Indicator (WTI) and Oil Temperature Indicator (OTI)
· Check whether thermometer pocket is filled with oil

· Check whether the connections of the CT for winding temperature indicator to the thermometer pocket is properly made as per the instructions given on the WTI terminal box.
· Check whether the contacts of WTI and OTI for alarm and trip are set at required temperatures depending upon ambient temperature and loading conditions. For oil filled transformers, the maximum permissible temperature rise above the ambient temperature is usually taken as 450C for oil and 550C for winding. In the case of cast resin transformers, the alarm contact of the winding temperature relay is usually designed to operate at 1400 C and trip contact at 1600 C for transformers upto 1000 kVA. For higher ratings, the temperatures are 1600 C and 1800C respectively.
· Calibration of the WTI/OTI may be checked with hot oil. Working of the WTI/RTD repeaters shall be checked at the control room.
(xii) Buchholtz relays
· Check the angle of mounting of the Buchholtz relay using a spirit level
· Check the floats for free movement
· Release air in the Buchholtz relay
· In the case of forced oil cooled transformers, make sure that the Buchholtz relay does not operate when the pumps are switched on
xiii) Magnetic Oil Level Gauge
Move the float level of the oil level indicator up and down between the end positions to ensure that the mechanism does not get stuck at any point. The low oil level alarm of the gauge shall be checked.

(xiv) Arcing horn gap

Check arcing horn gaps of bushings for conformity with standard values. The standard values are given below:

(xv) Tap changer
Check the sequence of operation of the tap changer for the following:
· manual operation
· local electrical operation
· remote electrical operation
· parallel operation

(xvi) General inspection
i. Heaters in cubicles, conservator, etc. shall be checked
ii. Any other alarm/trip, contacts of flow meters, differential pressure gauges, etc. shall be checked
iii. In the case of water cooled transformers, the pressure gauge readings on water and oil sides shall be checked to ensure that the water pressure is less than the oil pressure. The quantity of oil and water flow shall not be less than what is specified
iv. The angle of protection of the lightning shield provided for outdoor transformers shall be checked. The angle shall be less than 30 degrees
v. Check whether roller blocks are provided for the rollers of the transformer
Functional checks
After the visual inspection is complete, it is necessary to test proper functioning of various protective
relays and instruments. The following functional checks may be carried out.
1. Check the operation of the Buchholtz alarm and trip by injecting air through the test pet cock.
2. Test the OTI for alarm and trip.
3. Test the WTI for alarm and trip.
4. Check the working of the WTI / RTD (Resistance Temperature Device) repeaters at the
control room.
5. Test the OLTC – Oil surge relay for trip.
6. Check alarm for low oil level .
7. Check the REF relay for current setting
8. Check the differential relay for main and bias settings
9. Check the back up over current and earth fault relays for current and time.
10. Check the over voltage relay for voltage and time.
11. Check the instantaneous over voltage relay for voltage.
12. Check the over fluxing relay for voltage, frequency and time.
13. Check the cooler unit for
· over current setting of fans
· over current setting of oil pumps
· cooler supply failure alarm

· fan/pump trip alarm

.any mal- operation of the transformer Buchholtz relay when all the oil pumps are switched on simultaneously in forced oil cooled transformers

Pre-commissioning tests
Insulation Resistance test
Insulation Resistance test is the simplest and most widely used test to find out the soundness of insulation between two windings or between windings and ground. Insulation resistance is measured by means of insulation testers popularly known as ‘Megger’. The ‘Megger’ consists of a D.C power source (hand operated or electrically driven D.C generator or a battery source with electronic circuit ) and a measuring system. Microprocessor based insulation testers are also now available. The insulation test reveals the condition of the insulation inside the transformer. The insulation resistance values are affected by temperature, humidity and presence of dirt on insulators and bushings.
Selection of Insulation Testers
Insulation testers with test voltage of 500, 1000, 2500 and 5000 V are available. The recommended
ratings of the insulation testers are given below:

Factors influencing IR value
The IR value of transformers are influenced by
1. surface condition of the terminal bushing
2. quality of oil
3. quality of winding insulation
4. temperature of oil
5. duration of application and value of test voltage
Different IR values monitored in transformers
The following IR values are monitored in transformers
1. winding to ground. eg. HV to LV and earth connected together LV to HV and earth.
2. winding to winding. eg. HV to LV
3. all windings to ground .eg. HV and LV to earth.

Steps for measuring the IR
1. Shut down the transformer and disconnect the jumpers and lightning arrestors.
2. Discharge the winding capacitance.
3. Thoroughly clean all bushings
4. Short circuit the windings.
5. Guard the terminals to eliminate surface leakage over terminal bushings.
6. Record the temperature.
7. Connect the test leads (avoid joints).
8. Apply the test voltage and note the reading. The IR. value at 60 seconds after application of the test voltage is referred to as the Insulation Resistance of the transformer at the test temperature.
Minimum value of IR
The following values of IR at 30deg. C can be considered to be the minimum requirement for new oil
filled transformers.

The transformer IR values in oil drained condition will be 15 to 20 times more than in oil filled condition.
Influence of temperature on IR
IR. values decrease sharply with the rise in temperature of the oil. The following correction factors may be used for arriving at the IR value with difference in temperature.

Interpretation of Insulation Resistance value.
While interpreting IR values, importance shall be given to the variation of the values over a period of time rather than absolute values. For conclusive analysis, use only results from tests performed at identical conditions as IR values are affected by value of test voltage, temperature of oil, duration of application of voltage, humidity, extent of stress applied etc. IR values recorded over a period of time may be plotted as a curve to study the history of the insulation resistance. A curve showing a downward trend indicates a loss of IR due to unfavourable conditions such as oildeterioration, excessive moisture in paper, deterioration/damage to terminal bushings etc. A very sharp drop is a cause for concern and action shall be taken to ascertain the exact cause of insulation failure and for corrective steps.
Points to note
1. Transformers with OLTC have lower IR values when compared with transformers with off circuit tap changer.
2. Auto transformers have lower IR when compared to two winding transformers.
3. Transformer windings with graded insulation have lower IR when compared to fully
insulated windings.
4. If the non-measured winding terminals are not guarded, the megger will give a low reading.
5. Avoid meggering when the transformer is under vacuum.
Dielectric absorption and polarisation index tests
Dielectric absorption and polarisation index tests give a good indication of the condition of the insulation. This test is based on the comparison of absorption characteristics of good insulation versus absorption characteristics of humid or contaminated insulation.
Instruments/materials required
Motorised or electronic insulation testers of appropriate voltage
Stop watch
Logarithmic paper
Procedure for test
In this test, a test voltage is applied for an extended period of time, usually thirty minutes, using a megger of appropriate voltage. The megger readings are taken every 10 seconds for the first minute and thereafter every minute – upto 30 minutes. The procedure for measurement of IR under para (Insulation Resistance test) is followed here. Hand cranked instruments are not suitable as continuous application of voltage is not possible with such instruments. Motorised or battery operated insulation testers are used for the test. A curve is drawn showing the variation in the value of IR. against time on a logarithmic paper. The resultant curve is known as dielectric absorption curve. A typical dielectric absorption curve is shown in fig. 2.1.

Polarisation Index is the ratio of Insulation Resistance at 10 minutes to Insulation Resistance at 1 minute of application of test voltage.
Polarisation Index =Insulation Resistance at 10 minutes/Insulation Resistance at 1 minute.

Interpretation of Polarisation Index and Dielectric Absorption Curve
A steady increase in insulation resistance with continuous application of test voltage indicates that the insulation is clean and dry. Flat or ambulated curves demand reconditioning of the insulation. Polarisation index is a good appraisal of the condition of the insulation.

The following are the guidelines for evaluating the condition of transformer insulation with respect to Polarisation Index values.

Polarisation indices with respect to insulation resistance between HV and LV + earth , LV and HV+ earth , earth and HV+LV are evaluated to ascertain the real condition of the transformer insulation.
Two Voltage Test (Step Voltage Test)
This test is an extension of the dielectric absorption test. This has been recommended as a more conclusive indication of presence of moisture. Two separate dielectric absorption tests made at different voltages help to detect moisture in the winding. The higher test voltage should be about 4 to 5 times the lower one, (eg.2500 V and 500 V) but should not be so high as to damage the insulation. A wide spread between the two dielectric absorption curves indicates presence of moisture. If the insulation resistance value decreases substantially at a higher voltage, say more than 25 percent, it is a reasonable indication of presence of moisture in the insulation system.
Measurement of Tan delta
Various insulation resistance tests explained above indicate mainly the surface conditions and presence of moisture in the insulation. Measurement of loss factor, commonly referred to as tan delta reveals the internal condition of the insulation. With alternating currents, the absorption of the dielectric is intimately connected with the loss of power in the dielectric. This loss within an insulation structure is associated with the oscillation of polar molecules trying to orient themselves with the alternating electric field. Hence current flowing through the insulation leads the voltage by some angle which is slightly less than 90 degrees. This small angle between pure capacitive current and actual current represented by d (delta) is known as loss angle. The dielectric loss in an insulation is given by V2 w C tan d and hence proportional to tan d. If the insulation is perfect, the characteristic of tan delta versus the applied voltage is almost a horizontal line. If voids have crept in the insulation during manufacture or service, there will be substantial increase in tan delta with the applied voltage. Hence the absolute values of tan delta in a commercially manufactured equipment have comparatively little practical significance. But the variation in tan delta – ie. D tan delta – with respect to time is very important. The values found during maintenance testing should be compared with the initial values recorded before commissioning the equipment. A stable value of tan delta is indicative of insulation stability and small increase is indicative of normal ageing. Tan delta is
measured using tan delta measuring equipment.
Transformer Ratio Test
Transformer ratio test is conducted to ensure that the turns ratio tally with the name plate details and also that tap changer connections are done correctly. Ratio test is done using a transformer turns ratio tester or with voltmeters. With the turns ratio tester, the turns ratio is directly read on the tester for each tap and for each phase of the winding.The turns ratio can also be tested by applying a single phase ac voltage (approximately 230V) on the HV side and measuring the voltage on the low voltage side at all tap positions.
The results of the voltage ratio test may be recorded in tabular form as given below:

Voltage ratio test ( by voltmeter )

Short circuit current measurement
This test is carried out as a check for any loose contact in the tap changer, lead connections etc. In this test, all the 3 windings in the LV side of the transformer are short circuited. All contacts in the tap changer, lead connections and terminals are checked for proper contact. From a variable voltage source, a 3 phase balanced low voltage a.c supply is applied to the HV winding at rated tap and the current measured. The current measured at rated tap should tally with the calculated value of HV current at the applied voltage.
The value of HV current at the applied voltage is calculated as follows:

Repeat the test at different tap positions by lowering and raising taps. The current measured in the HV winding should tally with the calculated value of HV short circuit current.

Wide difference between the measured and calculated values of HV short circuit current is an indication of loose contact in tap changer or lead connections.
Measurement of Magnetising current
The magnetising current is measured to test any fault in the magnetic circuit and winding. The measured values are compared with the factory test values. A balanced three phase 415V ac supply is applied to the LV winding and the simultaneous current readings of the three phases are taken using low range a.c ammeters of the same accuracy class. For a core type transformer, the middle phase magnetising current will be approximately half that in other windings. In YyO, Dy1 and Dy11 connections, the currents in ‘u’ and ‘w’ phases will be nearly double the current in ‘v’ phase. In a Yd1 connected transformer, currents in ‘v’ and ‘w’ phases will be nearly equal and the current in ‘u’ phase more than that in ‘v’ and ‘w’ phases. In a Yd11 connection, currents in ‘u’ and ‘v’ phases will be nearly equal and the current in ‘w’ phase more than that in ‘u’ and ‘v’ phases. If the measured values widely differ from the above values or from the factory test values, there is reason to suspect some defect in the transformer core and the manufacturer may be consulted. The
measured values of magnetising current may be used as bench marks for the service life of the transformer. Sample format for recording the magnetising current is given below:

Test for magnetic balance
This test is done to find out the condition of stacking of core laminations, tightness of core bolts and perfection of magnetic circuit. The HV and LV sides are isolated by removing the bushing connections. A single phase supply of nearly 230V is applied to one phase of the star connected winding and the induced voltage in othertwo phases are measured. The voltage may preferably be applied on the HV winding, as applying voltage to LV winding may induce very high voltage in the HV winding. If the HV winding is connected in delta, the test may be conducted on the LV side after taking necessary precautions against accidental contact with the HV bushings.

When the voltage is applied to the middle phase, the induced voltage measured on the two other phases should be approximately equal. Where the voltage is applied to an extreme phase, the induced voltage on the middle phase should be substantially high when compared to the voltage induced in the other extreme phase. In each test, the sum of the induced voltages in two phases should be nearly equal to the applied voltage.
Tests may be carried out by connecting a series lamp (say 25 watts) at supply side to restrict higher current, if any. If the series lamp glows brightly or the induced voltage readings in different phases indicate zero or very low value or if the induced voltages show abnormal variation from the expected values, fault in the winding can be suspected.

For measuring the voltages, high impedance voltmeter like digital multimeter should be used. The test may be repeated by applying voltage to the second and third phases and measuring the induced voltages in other phases. When the magnetic circuit is balanced, there would be symmetry in the value of measured induced voltages. The measured voltages may be recorded in the sample format given below:

Phasor Group Test
Phasor relationship between HV and LV voltages is checked by this test. Without earthing the winding neutral points, interconnect one phase of HV winding – say 1U – to the corresponding phase of LV winding -2U and apply a balanced 3 phase low voltage to the HV winding. The phase sequence of the supply should be the same as the specified phase sequence of the transformer winding. Connections for Dy 11 and Dy1 transformers and the corrsponding vector groupings are given in figures 2.2 and 2.3. Measure the voltage between the primary and the secondary terminals. The following requirements shall be fulfilled depending on the vector group of the transformers.

If two transformers are available for test, the phasor groups can be compared easily by applying voltage from same source to identical bushings on the HV side and by measuring the voltage between identically marked terminals on the LV sides with single interconnection between either the neutrals or any one phase.
Test for Transformer Oil
Transformer oil is of petroleum origin and is used as a coolant and dielectric in transformers. Transformer oil in good condition and conforming to relevant standards will prevent deterioration of transformer insulation. As the transformer oil is, to some extent, exposed to air at site, it is always necessary to test the oil for various characteristics before the transformer is put to service. As the various tests for transformer oil are laboratory tests, details of these tests are beyond the scope of this book. Test procedures for various tests are given in the relevant standards of BIS, list of which are given at the end of this chapter in para (List of Indian Standards relevant to testing of Power transformers)
From the point of view of field tests, what is important is the method of and precautions for collecting the transformer oil and the limit values of various characteristics. However a rough test on the moisture content of the oil can be made at site by conducting a simple test, popularly called the crackle test. In this test, a piece of steel tube of approximately 25 mm dia is closed at one end and the closed end is heated to just under red hot . Now the hot end is plunged into the oil sample with the ear close to the open end. If the oil contains large quantity of moisture, a sharp crackle will be heard.Dry oil will only sizzle.
Sampling of oil – General precautions
Since the results of the tests prescribed for transformer oil largely depend on the impurities in the sample sent for testing, it is essential to keep the oil free from any contamination. The following precautions shall be taken while collecting samples of transformer oil.
1. For collecting the sample, glass containers with glass stoppers are preferred over metal type. Wax shall not be used for sealing the containers. The stopper may be covered with a piece of cloth packed with silica gel.
2. The container may be warmed to above the ambient air temperature in order to avoid any condensation of moisture.
3. Before collecting the sample, all equipments used for handling the oil must be washed with clean transformer oil. The oil used for washing must be discarded.
4. Flexible steel hose may be used for handling the oil. Some kinds of synthetic hoses are also suitable. Ordinary rubber hose should not be used as oil dissolves the sulphur in the rubber and thereby gets contaminated. The hose used must be clean and free from dust, rust and scale.
5. The operator shall take special care to see that his hands do not come in contact with the sample or the internal surface of the container.
6. The transformer oil shall be protected against all kinds of light radiation during transportation and storage.
Sampling procedure
1. Remove the valve shield if fitted.
2. Remove all visible dirt and dust from the valve with a lintfree clean cloth.
3. Run off sufficient quantity of oil- say 1 litre – to eliminate any contaminant that might have accumulated in the drain cock.
4. Rinse the container with the oil being sampled.
5. Fill the container by allowing the oil to flow against the side of the containers to avoid air traps.

6. Close and seal the container and store the samples in a dark place.
Evaluation of test results
Three samples of oil from the top and bottom of the tank are tested for various characteristics. For transformers of capacity below 1 MVA and where very high reliability is not expected the five characteristics given in table 2.1 shall be invariably tested and it shall be ensured that the test results are within the minimum/maximum limits.

In the case of transformers where very high reliability is required and in all cases where the capacity is 1 MVA or above, the additional characteristics given in table 2.2 shall also be tested. The test results shall be within the given limits.

Relay Tests
All protective relays , CTs, PTs and control wiring shall be tested as explained under the chapter for protective relays. The relays shall be set to suit the operating conditions and to coordinate with other sections of the system. The relay test results shall be documented for future reference.
Commissioning
After completing all the pre-commission tests given under section (Pre-commissioning tests), the pre-test checks under section (Pre-commission checks) are redone once again. All the protective relays and circuit breakers are tested for proper working. The relay settings are kept at a low value so that the transformer will get isolated if there is any internal fault.Allow a settling time of at least 24 hours for oil and then release air from all points. Now the transformer may be test charged from the incoming side on no-load and operated for about two hours.

Observe the transformer hum for any abnormality. Any vibration or abnormal magnetising current may also be observed. After continuous operation for about two hours, isolate the transformer and check the gas operated Buchholtz relay for any gas collection. Any dissolved air or air bubble that may be collected in the Buchholtz relay may be released and the transformer charged again on noload. All connected instruments may be checked for any abnormal indication. Now gradually load the transformer to full capacity and keep it under constant observation for at least 24 hours of operation. Check the oil and winding temperature at full load and compare with factory test values. After four or five days of service, test the oil for various characteristics, especially for BDV. Any gas collection in the Buchholtz relay may also be observed. If the test results and observations are found normal, the transformer may be cleared for regular service. After the transformer is put in service for some weeks with normal working temperature, all sealed joints shall be re -tightened.

The results of the various tests shall be recorded and kept in the station as a permanent record for future reference. Details such as place of erection, date of commissioning, protection given to the transformer etc. may be furnished to the manufacturer after commissioning.

List of Indian Standards relevant to testing of Power transformers

Appendix

 

 

 

Vector Groups

 

Transformer nameplates carry a vector group reference such at Yy0, Yd1, Dyn11 etc. This relatively simple nomenclature provides important information about the way in which three phase windings are connected and any phase displacement that occurs.

Winding Connections
HV windings are designated: Y, D or Z (upper case)
LV windings are designated: y, d or z (lower case)

Where:
Y or y indicates a star connection
D or d indicates a delta connection
Z or z indicates a zigzag connection
N or n indicates that the neutral point is brought out

Phase Displacement
The digits ( 0, 1, 11 etc) relate to the phase displacement between the HV and LV windings using a clock face notation. The phasor representing the HV winding is taken as reference and set at 12 o'clock. It then follows that:

Digit 0 means that the LV phasor is in phase with the HV phasor
Digit 1 that it lags by 30 degrees
Digit 11 that it leads by 30 degrees, etc

When transformers are operated in parallel it is important that any phase shift is the same through each. Paralleling typically occurs when transformers are located at one site and connected to a common busbar (banked) or located at different sites with the secondary terminals connected via distribution or transmission circuits consisting of cables and overhead lines

Basic Theory
An ac voltage applied to a coil will induce a voltage in a second coil where the two are linked by a magnetic path. The phase relationship of the two voltages depends upon which way round the coils are connected. The voltages will either be in-phase or displaced by 180 deg

When 3 coils are used in a 3 phase transformer winding a number of options exist. The coil voltages can be in phase or displaced as above with the coils connected in star or delta and, in the case of a star winding, have the star point (neutral) brought out to an external terminal or not.

Example - Dyn11
We now know that this transformer has a delta connected primary winding (D) a star connected secondary (y) with the star point brought out (n) and a phase shift of 30 deg leading (11).
What does Dd0, Dyn11, YNd5 etc. mean?

First symbol/symbols, capital letters: HV winding connection.
Second symbol/symbols, small letters: LV winding connection.
Third symbol, number: Phase displacement expressed as the clock hour number.


Winding connection designations

High Voltage
Always capital letters
Delta - D
Star - S
Interconnected star - Z
Neutral brought out - N

Low voltage Always small letters
Delta - d
Star - s
Interconnected star - z
Neutral brought out - n


Phase displacement
Phase rotation is always anti-clockwise. (international adopted convention)
Use the hour indicator as the indicating phase displacement angle. Because there are 12 hours on a clock, and a circle consists out of 360°, each hour represents 30°.
Thus 1 = 30°, 2 = 60°, 3 = 90°, 6 = 180° and 12 = 0° or 360°.
The minute hand is set on 12 o'clock and replaces the line to neutral voltage (sometimes imaginary) of the HV winding. This position is always the reference point.
Because rotation is anti-clockwise, 1 = 30° lagging (LV lags HV with 30°)and 11 = 330° lagging or 30° leading (LV leads HV with 30°)



To summarise:
Dd0
Delta connected HV winding, delta connected LV winding, no phase shift between HV and LV.
Dyn11
Delta connected HV winding, star connected LV winding with neutral brought out, LV is leading HV with 30°
YNd5
Star connected HV winding with neutral brought out, delta connected LV winding, LV lags HV with 150°

After some comments I've decided to include the following:

The phase-bushings on a three phase transformer are marked either ABC, UVW or 123 (HV-side capital, LV-side small letters)
Two winding, three phase transformers can be devided into four main categories (Clock hour number and phase displacement of those most frequently encountered in practice in brackets)

Group I - (0 o'clock, 0°) - delta/delta, star/star
Group II - (6 o'clock, 180°) - delta/delta, star/star
Group III - (1 o'clock, -30°) - star/delta, delta/star
Group IV - (11 o'clock, +30°) - star/delta, delta/star

(Minus indicates LV lagging HV, plus indicates LV leading HV)

Group I
Example: Dd0 (no phase displacement between HV and LV)
The conventional method is to connect the red phase on A/a, Yellow phase on B/b, and the Blue phase on C/c. Other phase displacements are possible with unconventional connections (for instance red on b, yellow on c and blue on a) By doing some unconventional connections externally on one side of the trsf, an internal connected Dd0 transformer can be changed either to a Dd4(-120°) or Dd8(+120°) connection. The same is true for internal connected Dd4 or Dd8 transformers.
Group II
Example: Dd6 (180° displacement between HV and LV)
By doing some unconventional connections externally on one side of the trsf, an internal connected Dd6 transformer can be changed either to a Dd2(-60°) or Dd10(+60°) connection.
Group III
Example: Dyn1 (-30° displacement between HV and LV)
By doing some unconventional connections externally on one side of the trsf, an internal connected Dyn1 transformer can be changed either to a Dyn5(-150°) or Dyn9(+90°) connection.
Group IV
Example: Dyn11 (+30° displacement between HV and LV)
By doing some unconventional connections externally on one side of the trsf, an internal connected Dyn11 transformer can be changed either to a Dyn7(+150°) or Dyn3(-90°) connection.
Additional Note
By doing some unconventional connections externally on both sides of the trsf, an internal connected groupIII or groupIV transformer can be changed to any of these two groups. Thus, an internal connected Dyn1 transformer can be changed to either a: Dyn3, Dyn5, Dyn7, Dyn9 or Dyn11 transformer, by doing external changes on both sides of the trsf. This is just true for star/delta or delta/star connections.
Changes for delta/delta or star/star transformers between groupI and groupII can just be done internally.
Transformer Power(kVA) = 1.732 x V x I



 

kVA

Amps@    33kV

Amps@  11kV

Amps@      6.6kV

Amps@       3.3kV

Amps@415V

Amps@400V

Amps@240V

kVA

kW                      (P.F. = 0.93)

10

 

 

1

2

14

14

42

10

9.3

15

 

 

1

3

21

22

63

15

14

20

 

 

2

3

28

29

83

20

18.6

50

 

 

4

9

70

72

208

50

46.5

75

 

 

7

13

104

108

313

75

69.8

100

2

5

9

17

139

144

417

100

93

150

3

8

13

26

209

217

625

150

139.5

200

3

10

17

35

278

289

833

200

186

250

4

13

22

44

348

361

1042

250

232.5

300

5

16

26

52

417

433

1250

300

279

400

7

21

35

70

556

577

1667

400

372

500

9

26

44

87

696

722

2083

500

465

600

10

31

52

105

835

866

2500

600

558

700

12

37

61

122

974

1010

2917

700

651

800

14

42

70

140

1113

1155

3333

800

744

900

16

47

79

157

1252

1299

3750

900

837

MVA

 

 

 

 

 

 

 

MVA

MW

1

17

52

87

175

1391

1443

4167

1

0.9

1.5

26

79

131

262

2087

2165

6250

1.5

1.4

2

35

105

175

350

2782

2887

8333

2

1.9

2.5

44

131

219

437

3478

3608

10417

2.5

2.3

3

52

157

262

525

4174

4330

12500

3

2.8

3.5

61

184

306

612

4869

5052

14583

3.5

3.3

4

70

210

350

700

5565

5774

16667

4

3.7

4.5

79

236

394

787

6260

6495

18750

4.5

4.2

5

87

262

437

875

6956

7217

20833

5

4.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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