TRANSFORMER MAINTENANCE MANUALBy Prof. VG Patel

MAINTENANCE PHILOSOPHYINTRODUCTION

In today's competitive market scenario power utilities are under tremendous pressure to cut down their maintenance costs as they form a significant portion of the operation costs. This has led the utilities to adopt condition-based maintenance of the equipments rather than usual preventive maintenance being carried out at a fixed interval of time. Maintenance intervals are normally fixed on the basis of type of equipment and sometimes on the equipment history. However, tests or measurements are also carried out to assess the condition of the equipment.

MAINTENANCE

• Maintenance is the combination of all technical and associated administrative actions intended to retain an item in, or restore it to, a state in which it can perform its required function throughout its life cycle.

• Function of system/equipment is to provide desired output at desired quality with control on hazards to safety of man/machine/environment.

MAINTENANCE – OBJECTIVES

Maximize system availability to the desired level with criteria of safety and economy.

• To retain or to restore equipment condition to perform its required function throughout life cycle.

• Maximize system availability to the desired level with a criteria of safety and economy.• If you attend to minor defects, major breakdowns never arise.• Secret of good maintenance is perfection and attention to details.

After maintenance, condition should improve. One should exercise practical approach / Judgment. Give clear cut instructions with reasoning part. Opportunity Maintenance should be adopted. Do not adopt make shift method. Haste in maintenance is waste in production.

TYPES OF MAINTENANCE

Different types of maintenance being done on equipment are:i) Breakdown maintenance

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ii) Preventive maintenance (Planned maintenance ORScheduled maintenance OR Time based maintenance).

iii) Condition based monitoring / Predictive Maintenanceiv) Reliability centered maintenance

i) Breakdown MaintenanceAs the name implies the maintenance is carried out when the equipment fails. This type of maintenance may be appropriate for low value items. However for costly substation equipments, it is not desirable to wait till the breakdown of the equipment, as this cost more to the utility as well as the availability and reliability of power gets affected. The revenue loss due to non-availability of the system shall be much more than the cost of the failed equipment. Therefore identifying the defect before failure is more appropriate to plan repair / replacement.

ii) Preventive MaintenanceThe preventive maintenance of equipment is being mostly adopted by almost all the utilities. In this type of maintenance, the equipments are inspected at a pre-determined period. The frequency determined based on the past experience and also guidance from the manufacturer of the equipment. This type of maintenance would require specific period of shut-down. Maintenance procedure, periodicity of maintenance and formats for maintaining records for various types of sub-station equipments have been discussed separately in detail in a separate section.

 iii) Condition Based Monitoring / Predictive MaintenanceThis type of maintenance technique is adopted to assess the condition of the equipment. The condition of the equipment is assessed based on different condition monitoring tests. Some of the tests are done on on-line and some are done on off-line. However, this type of maintenance would need sophisticated testing equipments and skills for analyzing the test results.

iv) Reliability Centered MaintenanceThis is the recent technique being adopted in maintenance philosophy. The basic objectives of reliability-centered maintenance are:

- Maintenance should keep the equipment at desired level of performance-Optimizing / minimizing the maintenance / shutdown period so as to enhance the

availability of the equipment.- Deferring / avoiding the replacement of components and major/minor over-hauls till it is

absolutely necessary.

Reliability centered maintenance policy is based on the life cycle cost concept and the decisionforreplacement of the equipment is taken based on techno-economic considerations. From the view point of RCM our objective should be to devise a system, which does not need periodic maintenance and at the same time predict in advance possible failures/problems of the equipment. To meet this aim we have to develop equipment which require either no or very little maintenance and on the other hand the concept of condition based maintenance should be implemented. Realization of this objective will result in enhancing availability, reliability and reduction in manpower for maintenance purposes.

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FAILURES OF EQUIPMENTSFailure of any equipment should be taken up seriously. Detailed analysis of each failure should be done which will help in reduction/stopping of repeated failures of same nature. It is general experience that in spite of doing regular maintenance, failure of the equipment can't be totally eliminated. Number of EHV equipment failures has been reported practically by all the utilities and some of them have been quite serious resulting in consequential damage to the adjoining equipment. Circuit breakers operating on high pressure when they fail, they explode like a bomb resulting in scattering of insulator pieces to a larger distance and damage to the adjoining equipment. Similar situation have also been faced with the failure of surge arrestors and current transformers. Some of the typical failures of equipment and the remedial measures adopted have been discussed in a separate section.

NEED FOR CONDITION BASED ASSESSMENT OF EHV EQUIPEMNTIn the present competitive environment, all utilities are making efforts to reduce the O&M expenditure. This puts lot of pressure on the utilities to minimize the outage period due to failure of equipment. This necessitates adopting of condition based monitoring as the Need of the Hour. This has necessitated all the power utilities to introduce condition based monitoring for EHV class equipment so that actual condition of the equipment and its residual life could determine. Modern techniques are available for condition based monitoring and the concept ofresidual life assessmentispicking up worldwide.

DON’TS & DO’S FOR POWER TRANSFORMER

DON’TS FOR POWER TRANSFORMER 1) Do not energies without thorough investigation of the transformer whenever any alarm

of protection has operated. 2) Do not re-energize the transformer unless the Buchholz relay gas is analyzed. 3) Do not re-energize the transformer without conducting all pre-commissioning checks.

The results must be comparable with results at works. 4) Do not operate the off-circuit tap switch when the transformer is energized. 5) Do not energize the transformer, unless the off-circuit tap switch handle is in locked

position. 6) Do not leave-off circuit tap switch handle, unlocked. 7) Do not leave tertiary terminals unprotected outside the tank; connect them to tertiary

lightning arrestors’ protection scheme, when connected to load. 8) Do not allow WTI/OTI temperature to exceed 650C during draying out of transformer

and filter machine temperature beyond 700C. 9) Do not parallel transformer which do not fulfill the Paralleling condition. 10) Do not use low capacity lifting jacks on transformer for jacking. 11) Do not move the transformer with bushings mounted (above 33 KV’ class). 12) Do not overload the transformer other than the specific limits as per IS: 6600. 13) Do not change the settings of WTI and OTI alarm and trip frequently. The setting

should be done as per the site condition. 14) Do not leave red pointer behind the black pointer in OTI and WTI. 15) Do not leave any connection loose.

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16) Do not meddle with protection circuits. 17) Do not allow conservator oil level to fall below 1/4 level. 18) Do not leave marshalling box doors open, they must be locked. 19) Do not switch off the heater in marshalling box except to be periodically cleaned. 20) Do not allow dirt and deposits on bushings, they should be periodically cleaned. 21) Do not allow unauthorized entry near the transformer. 22) Do not leave ladder unlocked, when the transformer is ‘ON’ in service, in case it is

provided. 23) Do not change the sequence of valve opening for taking standby pump and motor into

circuit. 24) Do not switch on water pump unless oil pump is switched on. 25) Do not allow water pressure more than oil pressure in differential pressure gauge. 26) Do not mix the oil, unless it conforms fully to IS: 335. 27) Do not allow inferior oil to continue in transformer. The oil should be immediately

processed and to be used only when BDV/ppm conforms to IS: 1866. 28) Do not continue with pink silica gel, this should immediately be changed or

regenerated. 29) Do not store Transformer for long after reaching site it must be erected and

commissioned at the earliest.30) Do not leave secondary terminal of an unloaded CT open 31) Do not keep the transformer gas filled at site for a longer period 32) Do not top up oil from conservator with air cell bag inside.

DO’S FOR POWER TRANSFORMER 1) Check and thoroughly investigate the transformer whenever any alarm or protection

operated. 2) Check air cell conservator (optional).3) Attend the leakages on the bushing immediately 4) Examine the bushing for dirt deposits on coats, and clean them periodically.5) Check the oil in transformer and OLTC for dielectric strength & moisture content and

take suitable action for restoring the quality. 6) Check the oil level in oil cup and ensure air passages are free in the breather. 7) Check the oil for acidity and sludge as per IS: 1866. 8) If inspection covers are opened or any gasket joint is to be tightened, then tighten the

bolts evenly to avoid uneven pressure.9) Check & clean the relay and alarm contacts. Check also their operation and accuracy

and if required, change the setting.10) Check the protection circuit periodically.11) Check the pointer of all gauges for their free movement.12) Clean the oil conservator thoroughly before erecting.13) Check the Buchholz relay. 14) Inspect the painting and if necessary retouching should be done. 15) Check the OTI & WTI pockets and replenish the oil, if required.16) Examine and replace the burnt or worn out contacts.17) Check all bearings and operating mechanism and lubricate them as per schedule 18) Open the equalizing valve between tank and OLTC, wherever provided at the time of

filling the oil in the tank.

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19) Connect gas cylinder with automatic regulator iftransformer is to be stored for long in order to maintain positive pressure.

20) Fill the oil in the transformer at the earliest opportunity at site and follow storage instructions.

21) Check the door seals of marshalling Box.22) Equalize the diverter compartment of the OLTC by connecting equalizing pipe

between flange joints provided on the tap changer head.23) Follow the oil filling instruction for topping up of oil for transformer with air cell type of

oil, preservation system.

TRANSFORMER IN FIELD

Engineering– Dynamic knowledge based on latest incidence.

In power transformer, important parameter is: Reliability of transformer - Depends on Design, Manufacturing processes, Row material,

Accessories and Operating practices & Maintenance.

WHAT CAUSES A POWER TRANSFORMER TO FAIL?The condition of the transformer deteriorates gradually right from the start, resulting in

Reduction in dielectric strength (i.e. the ability to withstand lightning and switching impulses).

Reduction in mechanical strength (i.e. the ability to withstand any through faults). Reduction in thermal integrity of the current carrying circuit (i.e. the ability to withstand

overloads). Reduction in electromagnetic (i.e. the ability to transfer electromagnetic energy at

specified conditions including over excitation and over loading).

Failure of power transformer is “two dimensional” Frequency of failure Severity of failure Generally “AGEING” should not be consider as a cause of “FAILURE” Now a day ,

- Switching surges are taken care by breaker design.- Ultra modern (very fast arcing) protection.- Use of modernsoftware and- Use of 3D modeling etc,- FEM / BEM calculations.

KEMA SURVEY- In S. C. test, out of 4 transformers,1 transformer fails & in field,one out of 10 Transformers fails. - Transformer can be reliable, if it is designed perfectly.

Transformer can be reliable, if it is designed Page 5 of 80

Electrically perfect Mechanically perfect Thermally perfect

Due to mechanical stresses, Buckling Loosening of wedges

Due to electrical stresses, Core saturation

Due to thermal stresses, Ageing of insulation

Kraft insulation – Solid insulation (Kraft is the name of process).

Failure – ModesMajor insulation

-Oil gap break down- Surface contamination- Degradation of impulse strength- Critical over voltage

Minor winding insulation (coil to coil, turn to turn)- H.V winding, 80%- Regulating winding- Break down of oil gap, Surface discharge and Creeping discharge

Thermal Mode - Design deficiency- Over heating of tap leads- Over heating of coils

Lead and connection- Over heating of the insulation of winding exit leads- Over heating soldered connection / bolted connection

Mechanical Mode- Looseness of winding clamping- Tilting of conductor of HV winding- Radial buckling of common winding of auto transformer and LV winding of step

down transformer.

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-

Early Failures - Caused by inherent defects due to poor materials, Workmanship or processing procedures or Manufacturer’s quality control beside installation problems.

Random failures - Caused by operating conditions such as a failure from switching surges, lightning surges and operator faults. Failure rate is

normally constant. Wear out Failures- Caused by material wear out. Normally, wear out mode

becomespredominant after about 20 years of operation.

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POINTS TO BE REMEMBERED

A transformer which has been commissioned and later withdrawn from service for any considerable time should be rechecked as when commissioned.

It is preferable not to mix oil from different manufacturers.

Before putting the transformer in to service, all air may have collected in the Buchholz Relay should be allowed to escape through the top petcock.

STANDARDS:

IEEE – The Institute of Electrical and Electronic Engineers IEC – The International Electro technical CommissionBS – British StandardsCSA – Canadian Standards AssociationAS – The Standards Association of AustraliaNETA – The International Electrical Testing Association

These are the standards the majority of the world would follow in the purchasing, testing, installing, loading and operating electrical Equipments.

IS: 335, IEC: 296, BS:148, etc. – Transformer oil.IS: 1886 – 1961 – Code of practice for maintenance of insulating oil.IS: 1886 – 1967 – Code of practice for maintenance of Transformer.IS: 2026, IS 1180 - Transformer

LIST OF INDIAN STANDARDS RELATED TO TRANSFORMERSSl. No. IS No. & year Specification

1 IS1885 – 1993 Electro technical Vocabulary

2 IS 2026 part1 1977 Power Transformers: General3 IS 2026 part2 1977 Power Transformers: Temperature rise4 IS 2026 part3 1981 Power Transformers: Insulation Level and Dielectric Tests 5 IS 2026 part4 1977 Power Transformers: Terminal markings, tapings and

connections.6 IS 2026 part5 1994 Power Transformers: Transformer/Reactor bushings minimum

external clearance in air.7 IS 6600 - 1972 Guide for loading of Oil immersed Transformers8 IS 10561 - 1983 Application guide for Power Transformers9 IS 11171 - 1985 Dry type Transformers

10 IS 10028 part1-1985 Code of practice for selection, installation and maintenance of transformers - Selection

11 IS 10028 part2-1981 Code of practice for selection, installation and maintenance of transformers- Installation

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12 IS 10028 part3-1981 Code of practice for selection, installation and maintenance of transformers- Maintenance

13 IS 1180 part1 -1989 Outdoor type three phase distribution transformers up to and including 100 kVA in 11kV –Non sealed type

14 IS 1180 part2 1989 Outdoor type three phase distribution transformers up to and including 100 kVA in 11kV –Sealed type

15 IS 1576 - 1992 Solid press board for Electrical purposes16 IS 2312 - 1967 Propeller type AC ventilating fans17 IS 3024 - 1997 Electrical steel sheets -Oriented18 IS 3231 - 1986 Electrical relays for Power system protection19 IS 3401 - 1992 Silica gel20 IS 3588 - 1987 Electric Axial flow fans21 IS 3637 - 1966 Gas operated relays22 IS 3639 - 1966 Fittings and accessories for transformer23 IS 4253 part1 -1980 Cork composition sheets – Plain cork sheets24 IS 4253 part2 -1980 Cork composition sheets -Cork and Rubber25 IS 6088 - 1988 Oil to Water Heat Exchangers for transformers26 IS 7404 part2 -1991 Paper covered copper conductors–Rectangular conductors27 IS 8468 - 1977 On load tap changers28 IS 9147 - 1979 Cable sealing boxes for oil immersed transformers29 IS 9700 - 1991 Activated Alumina30 IS 8478 - 1977 Application guide for On-load tap changers31 IS 5561 - 1970 Electric Power connectors32 IS 12943 - 1990 Brass glands for PVC cables33 IS 2099 - 1986 Bushings for alternating voltage above 1000 V34 IS 3347 - 1979 Dimensions of porcelain transformer bushings35 IS 335 - 1993 New insulating oil36 IS 1866 - 2000 Code of practice for maintenance and supervision of insulating

oil in service

Trouble Cause1.1 Overheating - Overloads

- Failure of cooling system- High ambient temperature

1.2 Sustained higher voltage on primary resulting in overheating of core due to over fluxing.

Poor voltage control of power system use of shunt reactance and tap changing transformer to control bus bar voltage within specified limit.

1.3 Frequent external short-circuits.

Insufficient clearances on overhead lines, accumulation of dust on insulation.

1.4 Short-circuit between adjacent turns, usually high voltage winding.

- Sharp corners on conductors cutting into insulation

- External short circuits. - Moisture in oil.- Fluctuating loads.

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- Transient over voltage.1.5 Internal short-circuit -Sustained overload and insulation failure

-Fault in tap changer-Failure of end turns of coil due to over voltage surges

-Bad solder joint causing local overheating and open circuit

-Ageing of insulation, abrasion of insulation resulting in internal short circuits.

1.6 Moisture in oil - Moisture in the oil while filling- Breather saturated- Defective seals

1.7 Rapid deterioration of oil - Excessive overloading- Breather saturated- Poor quality of oil

1.8 Carbon and other conducting particles in oil

- Sparking in oil, excessive temperature of oil

Failures of power transformers due to structural defects.1. Improper tightening of core bolts and clamps results in excessive vibrations of

laminations and noise.2. Improper supports and clamps for windings results in collapse of winding during

external short-circuits.3. Improper soldered joints results in heating of conductor joint and carbonization of oil.4. Insufficient bracing of leads from windings to terminals results in distortion of leads and

faults.5. Leaks in tank or sealing joints results in oil leakage, over heating and failure.6. Dust and salt spray deposits on the surface of bushing insulators results in flash and

spoiling of insulator surface.7. Clogging of cooling tubes results in reduced flow of cooling medium and overheating.8. Failure in bushing results in transformer failure.9. Failure in tap-changes results in transformer failure.

10. Excessive currents in secondary conductor results in over-heating of conductors and oil.

11. Loose connections in conducting parts results in over heating.

About 60% failures of transformers occur by inter-turn short circuits. It is difficult to pin point the cause of short circuit. Two important steps to be observed are:

- Not to load beyond permissible limits.- Keep the oil in good condition.

State the important step in maintenance of power transformers.It is essential to have periodic maintenance of power transformers by trained persons, and with maintenance facilities. The earlier notion that the transformer does not need maintenance is wrong. Transformer needs regular maintenance for satisfactory service.

The transformer maintenance includes the following:Page 10 of 80

- Routine daily inspection ……… DI- Routine weekly inspection …... WI- Routine monthly inspection .… MI- Quarterly inspection ………..…. QI- Annual inspection ……………... AI- Un-scheduled maintenance … US

1. Daily checks include the following: Check tank and radiators for unusual noise, oil and water leaks. Check oil level in conservator. Check oil level in main tank bushings. Check relief vents whether normal or open. Check whether cooling water is flowing, whether oil circulation pump is operating when

necessary, whether fans start when necessary. Check relay panel temperature indicators and confirm normal condition. Check position of tap-changer. See that all control/alarm/power/supply circuit switches are closed and fuses in the

circuit are well placed.

2. Monthly checks include the following: Check oil level in main tank, oil filled bushing etc. If oil level has fallen down below

specified level for given temperature the cause of leakage should be determined. Oil level varies with change in oil temperature. Check and record oil temperature. Check bushing surface for signs of chipping, dirt, oil film etc. Check presence of nets, vines, shrubs etc. in the neighborhood of transformers. Check terminal connections, earthing connections for tightness. Other checks mentioned in daily check.

3. Annual Inspection of Transformer and Tap-changer: Check foundation for cracking and settling. A slight shift of the transformers may break

bushings or connecting oil or water lines. See that rail stops are firmly in place to hold transformer in position on the rail. Check transfer car and matching of its rails with transformer deck rails at each position. Weld metal work as needed.

Clean dirt and oil from radiating surfaces. Repaint as necessary. Stop excessive vibration of radiator tubes, tighten loose or vibrating parts. Check for unusual internal noises. Inspect oil and water piping, valves and plugs. Manipulate radiator cut-of valves to see that they are in operating condition and secure in the open position. See that all oil drain valves which can be operated without wrenches are plugged or locked to prevent unauthorized opening.

See that relief diaphragm is in operating condition and closes tightly. The non-shattering-type diaphragm should be actuated to see that it is not stuck shut from rust or paint. Make sure that material used in shattering-type diaphragm is not too thick or tough to be broken by reasonable internal pressure. See that screens and baffles in the vents or breathers are not obstructed or broken. If breathers are of dehydrating type, check chemicals and replace it depleted.

Clean dirty gauge glasses and connections.

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Check oil level indicators and relays for proper operation. Replenish oil if below normal. Drain out and replace bushing oil if dirty or discoloured. Check external supply and drain piping for leaks. Flush out cooling coils of heat

exchanger water passages with air and water. Test coils for leaks by applying air pressure to coils and absorbingfor bubbles rising in oil and drop in air pressure with supply valve closed, or use a hydrostatic pressure test. A pressure of about 75 pounds per square inch is recommended. If water scale is present, circulate a solution of 25 percent hydrochloric acid and water through the coils until clean. The flush out thoroughly.

Clean external surfaces of coils. Check water flow indicators and relays for proper operation. Clean and test water tubes similar to cooling coil, check for oil and water leaks. Check motors and control. Check calibration of temperature indicators and relays, check and clean relay contacts

and operating mechanism. Check setting and operation of regulator and relay, see that gauges are indicating

properly. Check for gas leaks by applying liquid soap on all joints valves, connections, etc. with

gas pressure raised to the maximum recommended by the transformer manufacture. Clean porcelain with water, choroethylene, or other suitable cleaner. Repair chipped

spots by painting with lacquer suchas red glyptal. Inspect gaskets for leaks tighten bolts, check power factor, check oil sample from bottom of bushing for dielectric strength and presence of water which may be entering at top. Replace or replenish oil if necessary.

Check top settings and adjustment at terminal board to see that they agree with diagrams. Check insulation resistance of wiring with devices connected. Check ratio and phase-angle adjustments of potential devices if changes have been made in secondary connections and burden. Tighten connections, including potential device top, into bushing.

Tighten all bus and ground connections. Refinish joint contact surfaces if they have been overheating. Inspect ground cable to see that it is not loose or broken.

Lower the oil level to at least the top of the core. Inspect for sludge on core and windings. Inspect under side of cover for moisture and rust and clean up. Check connections at terminal board; tighten all bolted connections, core bolts, etc. with in reach.

Inspect contacts and clean if reachable on internal inspection. If not reachable for visual inspection, check each position with Wheatstone bridge across winding to detect poor contact. Work adjusted back and forth over complete range several times.

Drain oil from contact compartment, clean and refinish contact surfaces. Check contact spring pressure. Check contact operating mechanism. Tighten connections and other bolts of OLTC.

Check motor and adjust brake, check gears shafts and lubrication of OLTC. Check condition of contacts and refinish if burned or corroded. Check contact springs,

operating rods, and levers, check closing and operating position with respect to position of main contacts of OLTC.

See that positions indicated correspond to position of main contacts. Check remote electrical indicators for correct operation, obstruction to movement of pointer, etc.

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Check operation counter for correct registration. Run tap-changer or regulator through several complete cycles by both control relay

and manual control, and observe contacts and mechanism for proper operation. Inspect fuses or circuit breakers on all power, control and alarm supplies to auxiliary

equipment and devices. Check and tighten wiring connections at all terminal points. Inspect wiring for open circuits, short circuits, and damaged insulation. Check insulation resistance of wiring with devices connected.

Check the insulation resistance between each winding and between each winding and ground. Disconnect all external leads at the bushing leads terminals except where the connecting leads can be suitably isolated at adjacent disconnecting switches, for this test. Inspect wiring for open circuits, short-circuits and damaged insulation. A similar test using a capacitance bridge is recommended where such an instrument is available.

Check, the dielectric strength of the insulating oil in the main and auxiliary tanks and oil filled bushings.

The acidity of the insulating oil in the main tank should be checked at intervals of not more than 5 years. Transformers operating at high temperatures or showing signs of sludging or dark colour of the oil should be checked more frequently. Oil may be checked in the field with a dielectric test kit or samples sent to laboratory.

Un-scheduled Maintenance:If the transformer has been properly maintained and not overheated and barring internal failure, it should not require untanking within the normal life. If sludge has been allowed to form due to overheating and oxidation of the oil, transformer should be untanked and the core, coils oils passages, tank and water cooling coils washed down with clean oil under pressure to remove sludge and other accumulations which prevent proper circulation of the oil. Inflammable liquids should not be used in cleaning the core, coils, or inside of tank. While untanked, check for loose laminations, core bolts, insulating blocks etc. and other pertinent features on the check list.The necessity for filtering and/or reclaiming the insulating oil will depend on the results obtained from the oil dielectric and oil acidity tests. It may be more economical to replace the oil in small transformers rather than filter and reclaim it.

GENERAL

Transformers are so complex that it is impossible to put all symptoms and causes into a chart. Some transformer problems are listed below; there are many others.

(1) Problems with cooling systems, discussed in an earlier section, can cause overheating.

(2) A blocked oil duct inside the transformer can cause local overheating, generating gases.

(3) An oil directing baffle loose inside the transformer causes mis-direction of cooling oil.

(4) Oil circulating pump problems (bearing wear, impeller loose or worn) can cause transformer cooling problems.

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(5) Oil level is too low; this will not be obvious if the level indicator is inoperative.

(6) Sludge in the transformer and cooling system.

(7) Circulating stray currents may occur in the core, structure, and/or tank.

(8) An unintentional core ground may cause heating by providing a path for stray currents.

(9) A hot-spot can be caused by a bad connection in the leads or by a poor contact in the tap changer.

(10)A hot-spot may also be caused by discharges of static electrical charges that build up on shields or core and structures which are not properly grounded.

(11)Hot-spots may be caused by electrical arcing between windings and ground, between windings of different potential, or in areas of different potential on the same winding, due to deteriorated or damaged insulation.

(12)Windings and insulation can be damaged by faults downstream (through faults), causing large current surges through the windings. Through faults cause extreme magnetic and physical forces that can distort and loosen windings and wedges. The result may be arcing in the transformer, beginning at the time of the fault, or the insulation may be weakened and arcing develop later.

(13)Insulation can also be damaged by a voltage surge such as a nearby lightning strike or switching surge or closing out of step, which may result in immediate arcing or arcing that develops later.

(14)Insulation may be deteriorated from age and simply worn out. Clearances and dielectric strength are reduced, allowing partial discharges and arcing to develop. This can also reduce physical strength allowing wedging and windings to move extensively during a through-fault, causing total mechanical and electrical failure.

(15)High noise level (hum due to loose windings) can generate gas due to heat from friction. Compare the noise to sister transformers, if possible. Sound level meters are available at the TSC for diagnostic comparison and to establish baseline noise levels for future comparison.

Check List of Maintenance of Power TransformerLarge Transformer

(Above 1 MVA)Small Transformers

(Up to 1 MVA)Attended Unattended Attended Unattended

Dielectric Strength of oil AI AI AI AIBushings WI AI WI AI WI AI MI DITap Changer or Regular DI AI WI AIMotor and Drive Housing AI AIAuxiliary and Limit Switches AI AI

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Position Indicators AI AIOperation Counter WI AI WI AI WIOperation AI AITanks and Radiators DI AI WI AI WI AI MI AIMain Terminal and Ground Connections DI AI WI AI WI AI MI AI

Terminal Board and Connections AI AI AI AI

Foundation AI AI AI AIPiping of Oil and Water DI AI WI AI WI AI MI AIPlugs and Valves DI AI WI AI WI AI MI AIOil Levels DI AI M1 AI WI AI MI AIVents and Breathers DI AI M1 AI WI AI MI AIRelief Vents DI AI M1 AI WI AI MI AIWater Cooling Piping AI AI AI MI AIFlow Indicators and Relays DI AI AI DI AI AIHeat Exchangers AIOil Pumps DI AICooling Fans DI AI DI AITemperature Indicators DI AI M1 AI WI AI MI AICore and Coils US US US USInternal inspection AI AI AI AIPower Supplies and Wiring DI AI M1 AI WI AIInsulation Resistance AI AI AI AIOil Filtration US US US US

DI=Daily inspection, WI=Weekly Inspection, MI=Monthly Inspection, AI= Annual Maintenance

Typical Maintenance schedule for Transformers up to 1000 kVAFrequency of

InspectionInspection Inspection Details Action required if

conditions are unsatisfactory

1. Hourly * Load (amperes) Temperatures, voltage

Check against rated figures

Start fans if necessary

2. Daily Dehydrating breather

Check that air passages are clear. Check colour of active agent

If silica gel is pink charge, may be reactivated for use again

3. Monthly Oil level in transformer

Check transformer oil level

If low, top up with dry oil. Examine transformer for leaks.

4. Quarterly Bushings Examine for cracks and dirt deposits

Clean or replace

5. Half-yearly No conservator Check for moisture Improve ventilation, Page 15 of 80

cover check oil6. Yearly Oil in transformer Check for dielectric

strength and water content. Check for acidity and sludge.

Take suitable action to restore quality of oil

” Earth Resistance - Take suitable actions if earth resistance is high.

” Relays, alarms, their circuits etc.

Examine relay and alarm contacts, their operation, fuses, etc. Check relay accuracy etc.

Clean the components and replace contacts and uses if necessary any. Change the setting if necessary.

7. Two Yearly Non-conservator transformers

Internal inspection above core.

Filter oil regardless of condition

8.Five Yearly, after internal fault

- Overall inspection, lifting of core and coils

Wash by hosing down with clean dry oil

1 to 6 ---- minor repairs, 7 ---- Medium repair, 8 ---- Major Repairs

* If oil temperature or winding temperature exceeds safe limit, fans are started. If necessary load is reduced by switching in another transformer.

A rigid system of preventive maintenance will ensure long life. Log books and history-records should be mentioned for each transformer.No work should be done on the transformer unless it is disconnected from supply, terminals, tank, cover are solidity earthed.

Typical Maintenance schedule for Transformers above 1000 kVAFrequency

of Inspection

Inspection Inspection Details Action required if conditions are unsatisfactory

1. Hourly Ambient temperature

- -

” Winding temperatureOil Temperature

Check that temperature is reasonable

If abnormal heating, shut down the transformer and investigate if heating is persistently higher than normal

” Load (amperes) Voltage

Check against rated figures

-

2. Daily Oil level in trans-former

Check against transformer oil level

If low, top up with dry oil, examine transformer for leaks

” Oil level in bushing - -” Leaking of water - -

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into cooler” Relief diaphragm - Replace if cracked or broken” Silica gel breather Check that air

passages are free. Check colour of active agent.

If silica gel is pink change by spare charge. The old charge may be reactivated for use again.

4. Quarterly Bushing Examine for cracks and direct deposits

Clean or replace

” Oil in transformer Check for dielectric strength and water content.

Take suitable action to restore quality of oil.

” Cooler fan bearings, motors and operating mechanism

Lubricate bearings. Check gear box. Examine contacts Check manual control and interlocks.

Replace burnt or worn contacts of other parts.

4.Half yearly Oil cooler Test for pressure. -5. Yearly or earlier if the transformer can conveniently be taken out for checking.

Oil in transformer Check for acidity and sludge.

Filter or replace

” Oil filled bushings. Test Oil. Filter or replace” Gasket joints - Tighten the bolts evenly to

avoid uneven pressure.” Cable boxes Check for sealing

arrangements for filling holes. Examine compound for leaks

Replace gaskets, if leaking.

” Surge diverter and gaps

Examine for crack and dirt deposits

Clean or replace

” Relays, alarms, their circuits, etc.

Examine relay and alarm contacts, their operation, fuses, etc. Check relay accuracy etc.

Clean the components and replace contacts and fuses, if necessary. Change the setting if necessary.

” Earth Resistance - Take suitable action; if earth resistance is high

6. 5 yearly 1000 to 3000 kVA Overall inspection, including lifting of core and coils

Wash by housing down with clean dry coil

Note:

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The manufacturer’s recommendation should be followed for maintenance and repairs.

The silica gel may be reactivated by heating it to 1500 to 2000 Celsius.

Every time the drying medium is changed, oil seal should also be changed.

No work should be done on any transformer unless it is disconnected from all external circuits, and the tank and all windings have been solidly earthed.

In case of anything abnormal occurring during service, maker’s opinion should be obtained, giving him complete particulars as to the nature and the external of occurrence, together with the name-plate particulars in order to assist identifications.

COOLANTSMineral oilMineral oil surrounding a transformer core-coil assembly enhances the dielectric strength of the winding and prevents oxidation of core. Dielectric improvement occurs because oil has a greater electrical withstand than air. Because the dielectric constant of oil (2.2) is closer to that of the insulation, the stress on the insulation is lessened when oil replaces air in a dielectric system. Oil also picks up heat while it is in contact with the conductors and carries the heat out to the tank surface by self-convection. Thus a transformer immersed in oil can have smaller electrical clearances and smaller conductors for the same voltage and KVA ratings.

AskarelsBeginning about 1932, a class of liquids called askarels or polychlorinated biphenyls (pcb) was used as a substitute for mineral oil where flammability was a major concern, askarel-filled transformers could be placed inside or next to a building where only dry types were used previously. Although these coolants were considered nonflammable, as used in electrical equipment, they could decompose when exposed to electric arcs or fires to form hydrochloric acid and toxic furans and dioxins. The compounds were further undesirable because of their persistence in the environment and their ability to accumulate in higher animals, including humans. Testing by the U.S environmental protection agency has shown that PCBs can cause cancer in animals and cause other non-cancer health effects. Studies in human provide supportive evidence for potential carcinogenic and non-carcinogenic effects of PCBs. The use of askarels in new transformer was outlawed in 1977 (Claiborne, 1999) work still continues to retire and properly dispose of transformers containing askarels or askarel contaminated mineral oil. Current ANSI/IEEE standards require transformer manufacturers to state on the nameplate that new equipment left the factory with less than 2 ppm PCBs in the oil (IEEE, 2000).

High – Temperature HydrocarbonsAmong the coolants used to take the place of askarels in distribution transformers are high-temperature hydrocarbons (HTHC), also called high-molecular weight hydrocarbons. These coolants are classified by Nation Electric Code as “less flammable” if they have fire point

Page 18 of 80

above 300º C. The disadvantages of HTHCs include increased cost and a diminished cooling capacity from the higher viscosity that accompanies the higher molecular weight.

SiliconesAmong coolant that meets the National Electric Code requirements for a less-flammable liquid is a silicone, chemically know as polydimethylsiloxane. Silicones are only occasionally used because they exhibit biological persistence if spilled and are more expensive than mineral oil or HTHCs.

Halogenated fluidsMixtures of tetrachloroethane and mineral oil were tried as an oil substitute for a few years. This and other chlorine based compounds are no longer used because of a lack of biodegradability, the tendency of produce toxic by products, and possible effects on the earth’s ozone layer.

EstersSynthetic esters are being used in Europe, where high-temperature capability and biodegradability are most important and their high cost can be justified for example, in traction (railroad) transformers. Transformer manufacturers in the U.S are now investigating the use of natural esters obtained from vegetable seed oils. It is possible that agricultural esters will provide the best combination of high temperature properties, stability, biodegradability, and cost as an alternative to mineral oil in distribution transformers (Oomen and Claiborne, 1996). CONCLUSION ON COOLANTSFor many decades the mineral oil is used for electrical insulation provision in high voltage installations, mainly, in electrical power transformers. By now a great amount of experimental information devoted to researches of the (mineral oil – transformer design materials) system ageing is accumulated all around the world. In neutron generators with oil insulation, designed materials in a contact with oil is significantly wider and differ from materials used in transformers. There is a considerable difference in working conditions as well.Inspite of being rather old and non ‘high-tech’ product, mineral oil still have good “price-quality” ratio for commercial products.

AIR CELL

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Conservator with Bladder or Diaphragm Design: A conservator with bladder or diaphragm is similar to the design above with an added air bladder (balloon) or flat diaphragm in the conservator. The bladder or diaphragm expands and contracts with the oil and isolates it from the atmosphere. The inside of the bladder or top of the diaphragm is open to atmospheric pressure through a desiccant air dryer. As oil expands and contracts and as atmospheric pressure changes, the bladder or diaphragm "breathes" air in and out. This keeps air and transformer oil essentially at atmospheric pressure. The oil level gage on the conservator typically is magnetic, like those mentioned earlier, except the float is positioned near the center of the underside of the bladder. With a diaphragm, the level indicator arm rides on top of the diaphragm. Examine the air dryer periodically and change the desiccant when approximately one-third of the material changes color.

Note: A vacuum will appear in the transformer if piping between the air dryer and conservator is too small, if the air intake to the dryer is too small, or if the piping is partially blocked. The bladder cannot take in air fast enough when the oil level is decreasing due to rapidly falling temperature. Minimum ¾- to 1inch piping is recommended. This problem is especially prevalent with transformers that are frequently in and out of service and located in geographic areas of large temperature variations. This situation may allow bubbles to form in the oil and may even activate gas detector relays such as the Buchholz and/or bladder failure relay. The vacuum may also pull in air around gaskets that are not tight enough or that have deteriorated (which may also cause bubbles).

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Bladder Failure (Gas Accumulator) Relay: The bladder failure relay (not on diaphragm-type conservators) is mounted on top the conservator for the purpose of detecting air bubbles in the oil. Shown at right in figure is a modern relay. Check your transformer instruction manual for specifics because designs vary with manufacturers. No bladder is totally impermeable, and a little air will migrate into the oil. In addition, if a hole forms in the bladder, allowing air to migrate into the oil, the relay will detect it. As air rises and enters the relay, oil is displaced and the float drops, activating the alarm. It is similar to the top chamber of a Buchholz relay, since it is filled with oil and contains a float switch.

Caution: (1) Never open the vent of the bladder failure relay unless you have vacuum or pressure

equipment available. The oil will fall inside the relay and conservator and pull in air from the outside. You will have to re-commission the relay by valving off the conservator and pressurizing the bladder or by placing a vacuum on the relay. See your specific transformer instruction manual for details.

(2) When the transformer, relay, and bladder are new, some air or gas is normally entrapped in the transformer and piping and takes a while to rise and activate the relay. Do not assume the bladder has failed if the alarm activates within 2 to 3 months after it is put into operation. If this occurs, you will have to re-commission the relay with pressure or vacuum. See your specific transformer instruction manual for details. If no more alarms occur, the bladder is intact. If alarms continue, look carefully for oil leaks in the conservator and transformer. An oil leak is usually also an air leak. This may be checked by looking at the nitrogen and oxygen in the dissolved gas analysis. If these gases are increasing, there is probably a leak; with a sealed conservator, there should be little of these gasses in the oil. Nitrogen may be high if the transformer was shipped new filled with nitrogen.

Every 3 to 5 years: (if the conservator has a diaphragm) remove the conservator inspection flange and look inside with a flashlight. If there is a leak, oil will be on top of the diaphragm,

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and it must be replaced. The new diaphragm material should be nitrile. If the conservator has a bladder and a bladder failure relay, the relay will alarm if the bladder develops a leak. If the conservator has a bladder and does not have a bladder failure relay, inspect the bladder by removing the mounting flange and look inside with a flashlight. If there is oil in the bottom of the bladder, a failure has definitely occurred, and the bladder must be replaced. Follow procedures in the specific transformer instruction manual for draining the conservator and replacement; designs and procedures vary and will not be covered here.

TROUBLE SHOOTING CHART FOR TRANSFORMER INDICATIONS CAUSE CHECK/TESTITEMS

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DIFFERENTIAL RELAY AND BUCHHOLZ/PRV ACTED

TOGETHER.

INSULATION RESISTANCE VOLTAGE RATIO EXCITING CURRENT IMPEDANCE RESISTANCE MAGNETIC BALANCE

TRANSFORMER TRIPS

TRANSFORMER ACTIVE PART IS FAULTYPRV & BUCHHOLZ RELAY

ACTIVATEDTOGETHER.

HIGH IN RUSH CURRENT DEFECTIVE RELAY INCORRECT BIAS

SETTING

CHECK RELAY SET VALUE. MEASURE IN RUSH CURRENTONLY DIFFERENTIAL RELAY

ACTED

CHECK WIRING CHECK CONTACTS OF SWITCHES. CHECK WHETHER VALVE BETWEEN

CONSERVATOR AND TANK IS OPEN OR NOT

FAULTY OPERATION OF RELAY

ONLY BUCHHOLZ TRIP RELAY ACTED

ANALYSE GASES CHECK FOR SUDDEN DIP

ATMOSPHERE PRESSURE, AMBIENT TEMP., LOAD.

CHECK WHETHER OIL PUMPS ARE STARTED OR STOPPED.

CHECK WHETHER GASES ARE FLAMMABLE OR NOT.

ONLY PRV OPERATED

ONLY BUCHHOLZ ALARM ACTED

TRAPPED AIR OR EVOLUTION

OVER CURRENT RELAY, EARTHFAULT RELAY OR

LIGHTING ARRESTER ACTIVATED

CHECK WHETHER TRANSFORMER FED A SHORT CIRCUIT

CHECK WHETHER SHORT CIRCUIT OCCURRED DURING TAP CHANGING.

CHECK RELAYS

EXTERNAL FAULT

Prime SuspectSecondary Suspect

PERIODIC INSPECTION AND MAINTENANCE OF TRANSFORMER

Daily and periodic inspection schedule should be fixed with due consideration of transformer type, its importance in transmission system and loading requirements.

DAILY INSPECTIONThe objective of this inspection is to ensure that transformers are operating normally by going round the transformer. By which even slightest developing failures, if any shall be found and rectified at early stages.The go-round frequency depends on the operation monitoring system applied and importance of installation, but it is recommended to perform the inspection at least once a day.PERIODIC INSPECTIONDetailed inspection cannot be made by the daily inspection or go round inspection. Therefore an additional inspection should also be made periodically even if no abnormality is found by the daily inspection.

DAILY INSPECTION

Check the following items when going round the site for daily inspection:Parts Items to checked Check procedure

1.Transformer

1.Temperature *Ambient temperature (water temperature for water cooled trans,) *Oil temperature *Winding temperature

Remember the relations between ambient, load, oil temperature. Check temperatures referring to these values.

2 Oil level Oil level should be correct in relation with oil temperature

3.Abnormal excitation sound and vibration

Take special care for abnormal sound and vibration

4.Oil leakage Make sure that there is no oil leakage2.Cooler 1.Abnormal sound and

vibrationCheck whether cooling fans or pumps makes abnormal sound or vibration. For water cooled transformers check for abnormal sound from water pipes. When spare fans or pumps are switched on, extra care should be taken in this.

2.Oil leakage Check cooler valve, radiator and oil pump for leakage. For water cooled transformer check oil is leaking into the water

3.Abnormal operation Check whether fans and pumps tripped.Check oil flow and water indicators functioning properly.

4.Dust Make sure that cooling effect of radiator is not reduced because of dust collection on radiators.

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3.On loadTap

changer

1.Oil level When oil level rises abnormally there is a possibility of oil inside transformer leaking in to the OLTC when such trouble occurs contact manufacturer immediately

2.Oil leakage Make sure that there is no oil leakage3.Abnormal sound and vibration

Abnormal sound and vibration should not be produced during operation

4.On-Load oilPurifier

1.Oil leakage Make sure that there is no oil leakage2. Operation Operate once in a month manually when

going round for daily inspection and check for abnormal sound and vibration

5.Silica gel breather

1.Moisture absorbed by silica gel

When 2/3 part or more of silica gel is discolored to pink dry it to reactivate.

2.Oil level in oil cup Make sure breathing operation takes place by looking movement of oil in oil cup.

6.Bushings 1.Oil leakage Check care fully the discoloration of porcelain and oil leakage

2.Oil level Make sure that oil level is not lowered abnormally

3.Breakage, contamination, and over heated terminal

Check visually. Take special care for dust/salt accumulation.Pay special attention to corona discharge sound due to contamination and discolouration due to over heating(use of heat sensitive paint is recommended on terminal)

7.Pressure relief valve

1.Oil leakage There should not be any symptom of oil spillage

2.Operation Flag indication for operation should not found in operation condition

PERIODIC INSPECTIONFor detailed description and its procedure refer to instruction manual of each accessory.

Parts Check items

Interval Description / procedure

Criterion

TRANSFO

Measurement of Insulation resistance

Arbitrarily determined

1.Measure insulation resistance by 2000 Volt or more Megger2.Measurement should be made between each winding and earth3. Initial measurement may be made with

1.Measured value should be evaluated by table given in sec 2.12. If measured value differs greatly with value obtained during commissioning tests, detailed investigation to be carried out.3.Insulation resistances are influenced by external

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RMER

bushing connected.4.If measured value is abnormal measurement may be made again after disconnection the external leads

causes, therefore interpretation of results should be don in conjunction with the oil tests results

INSULATING

OIL

1.Measurement of BDV

1 year Measure by BDV tester with 2.5 mm gap

Insulation oil serves as the main insulation material of transformer and decrease of its insulation break down voltage will result in failure

2.Measurement of water content

2 to 3 years Measurement by Karl fishcer method

As water content in oil and in insulation materials will be in equilibrium there fore water content in oil changes with temperature. This makes judgment of whether oil absorbed moisture or not, difficult.

3. Analysis of gas in oil

1.Periodic measurement0.5 to1 year2.Additional measurement*When inflammable gas is found in Buchholz relay*After Buchholz relay is acted.*After oil is filtered or drained for repair.After welding is carried out on tank

Measurement is to be done by gas chromatographyComponent gases to analyze.O2 – OxygenN2 --NitrogenH2 --HydrogenCO –Carbon monoxideCO2 --Carbon dioxideC2H2 --AcetyleneCH4 ---MethaneC2H4 ---EthyleneC2H6----EthaneComponent gases used to determine normal or abnormal conditionH2, CH4, C2H2, C2H4, C2H6

Following gases shows deterioration:CO,CO2, CH4

Following conditions indicates abnormal cases*When total amount of inflammable gases exceeds 0.06% by volume.*When slightest amount of C2H2 (Acetylene) is found.* When pattern differ greatly from earlier measured data.Note –*Oil sample shall be collected from where there is good circulation oil.*During sampling make sure that gases are not escaped to atmosphere.*Temperature of transformer and load are also to be recorded

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4.Measurement of BDV and neutralization value of oil in diverter compartment

1 year Measure by BDV testerMeasure by chemical analysis

When BDV is 20kV or less or neutralization value is 0.3 mg/KOH/gm or more, change the oil.Change oil whenever diverter switch is removed for repair.

Parts Check items

Interval Description / procedure

Criterion

OLTC

1.Internal inspection of resistor type diverter switch

1. After commissioning new transformer, check diverter after 1000 operations.2.Check after 50000 operations or after 5 years of operation, which ever is earlier( for tap changers provided with on line purifier)3.Check after 30000 operations or after 3 years of operation, which ever is earlier( for tap changers provided without on line purifier)It is desirable to check diverter switch whenever transformer is subjected to sustained short circuit

1.Contacts of diverter Contacts should not worn out excessively due to arcing

2.Breakage and deformation of transition resistor

The resistors should not be broken, deformed or covered with excessive deposit

3.Loosening of fastening parts

No fastening part should found loose

4.Breakage No breakage should found on springs insulation supports etc.

5.Mechanical parts Sliding parts should not be worn out, corroded or scratched.

6.Carbon deposits The mechanical parts insulators and transition resistors should not be covered with excessive carbon

2.Inspection of driving

1 to 2 yearFirst check after 10000 operations

1.Operation Abnormal sound and vibration should not be produced during operation

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mechanism and its driving shaft

2.Measurement of Insulation resistance

1mega ohm or more by 500 volt Megger.

3.Mechanical parts The mechanical parts should not be worn out, loose or corroded.

3.Online oil purifier

1 year 1.Oil leakage Oil leakage should not exist.

2.Abnormal sound during operation

Abnormal sound should not be produced

3Thermo meter and pressure gauges

Should work properly

4.Operation of timer The timer should operate normally.

Parts Check items

Interval Description / procedure

Criterion

ACCESSORIES

1.Marshalling box and protective equipments

1 year Operation of switches, relays, protective devices and contacts

These devices should operate normally

2.Bushings

2 to 3 years 1.Oil leakage and oil level

No oil leakage should exist.

2.Breakage of porcelain

No breakage should found

3.Terminals and cap Terminals and cap should not be loose or discoloured due to over heating.

4.If bushing is contaminated with excessive dust/salt deposit, clean bushing with water

No contamination should exist.

5.tan measurement tan should not vary excessively from initial measurement

3.Dail type thermo meters

1to 2 years 1.temperature indication and pointer movement

Inspection and adjustment should be made when indicating value has large error.

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ACCES

2. Presence of moisture absorption, condensation, and corrosion

Remove moisture from inside

3.Operation of alarm and trip contacts

Continuity of contact should be normal

4. Breakage and cracks of acrylic glass.

Broken/cracked acrylic cover should be replaced with new one.DO NOT CLEAN ACRYLIC COVERS WITH SOLVENT SUCH AS PETROL, THINNER, KETONE

4.Mercury/ alcohol thermometer

2 to 3 years 1. Discontinuation of mercury / alcohol column.

Mercury/ alcohol column should not be broken

2.Temperature indication

Thermometers are to be replaced if indicationIs wrong.

3.Oil leakage from mounting

Oil should not leak from mountings.

5.Buchholz relay

2 to 3 year 1.Oil leakage Oil leakage should not be found.

2.Presence of gas Gas should not found collected in relay (if found collected carry out DGA)

3.Operation of alarm and tripping contacts

Continuity of contacts and display on control panel should be normal

4.Breakage No breakage should exist6.Pressure relief valve

2 to 3 year 1.Oil leakage Symptom of oil leakage and spilling should not be found.

2.Breakage of cover springs etc.

No breakage should exist and continuity of contacts should be normal

7.Conservator

2 to 3 yearCheck water drain valve every three months

1.Oil level Relation ship between oil temperature and oil level should tally

2.Oil leakage Oil leakage should not be found.

3.Water drain If water drained is more check gasket joints.

4.Brekage of air cell Air cell should not be broken.

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SORIES

8.Silica gel breather

2 to 3 year 1.Degree of moisture absorptionGood—blueMoisture absorbed - pink

When 2/3 part of silica gel is turned to pink dry it to reactivate or replace it with new charge

2.Breakage of silica gel container/ oil cup

Replace broken parts.

3.Oil level and contamination in oil cup

If oil is contaminated replace it with new oil

4.Breathing operation Watch care fully the oil movement in cup and make sure transformer is breathing.

9.Magneetic oil level gauge

2 to 3 year 1.Oil level indication Oil level should correspond to oil temperature of transformer. If this is not matching check float, add oil.

2. Contamination on dial /breakage of front glass.

Clean dial with cloth. Replace broken glass.

3.Circuit check Alarm/Trip function should operate when contact is made ON.

10.Oil pump

1to 2years 1.Abnormal sound If pump produces abnormal sound checkand replace bearing

2.Oil leakage and corrosion

Oil leakage and corrosion should not exist.

11.Oil flow indicator

1to 2years 1.Oil leakage Oil leakage should not exist

2.Breakage Acrylic cover should not be broken

3. Pointer movement. The pointer should indicate FLOW during operation. If abnormality is found check internal parts for damages, wear and looseness.

12.Fan motors

1to 2years Abnormal sound If fan motors produces abnormal sound checkand replace bearing

13 Cooler(air

1 year 1.Oil leakage Oil leakage should not exist

2.Corrossion Parts should not have corroded

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ACCESSORIES

cooled type)

3.Dust Cooler should be free from dust and insects.Clean the cooler once or twice a year.

14.Cooler(water cooled type)

1 to 2 yearsFirst inspection shall be made after a year

1.External check Should be free from water leakage and corrosion.

2.Inspection after dismantling

Abnormalities such as corrosion, wear, oil leakage and water leakage should not exist

15.Flexible coupl-ings

1year 1.Inspection for cracks

Cracks should not exist.

2.Oil leakage Oil leakage should not exist

16. Water quality check for water-cooled transformer.

Twice a yearIn first test perform tests specified in group (a) and in second perform tests in group (b)

a) pH, conductivity,Chlorine ion and total hardness.b) pH, conductivity,chlorine ion, total hardness, sulphate ion,M-alkalinity, sulphur ion, ammonia ion, total iron and silica

Item Ref valuePH at 25C

6.0 8.0

Conductivity at 25 C ( mho cm)

500

Chlorine ion (ppm)

100

Total hardnessNaco3

(ppm)

150

Sulphate ion (ppm)

200

M-alkalinityCaCO3

(ppm)

1560

Sulphur ion (ppm)

Not to be detected

Ammonia ion

Not to be detected

Total iron (ppm)

0.5

Silica (ppm)

30

AC

17.Checking of control

2 to 3 years 1. Operation of alarm and tripping contacts of each accessory.

When contacts are made ON display should appear on control panel

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CESSORIES

and protection circuits

2.Checking start and stop of cooling fan motors and oil pumps

Control sequence shall be confirmed.Magnetic contactors should operate normally

3. Measurement of insulation resistance of control cables to ground.

Insulation resistance should be more than 2 mega ohms.

4. Tightness of wires in terminals.

Terminals should not be loose nor should they be discoloured or fused.

Internal check

Arbitrarily determinedThe internal check is preferred when test results shows internal abnormality or when transformer subjected to sustained short circuit.

Depending on test results internal inspection should be done in 3 stepsa) Drain oil up to core top level.b) Drain oil completely.c) Lift internal parts out side from the tankWhatever the fault, check the following items during internal inspection.

Internal abnormality is judged from test results and by analyzing dissolved gases.Operation records, gas analysis data, earlier test data etc. should be kept handy to use the same to arrive to decision during inspection.

*Winding and connection wiresa)conductor deformationb)insulation damagesc)sludge depositsd)tightness of coil clamping boltse)broken connection wiresf)damaged supportsg)dislodged coil supports

No deformation should be noticed on windingInsulators should not be broken/ covered with sludgeCoil clamping bolt should be retightenedNo damage should be noticed on connection wires and its supportsAll coil supports should be in position

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*CoreTraces of core short, discolouration, deformation and corrosion Insulation core bolts their tightness and earthing status

Core should not be discoloured nor corroded due to over heating.Fastening parts should not be loose. Insulation should not be found damaged. Earthing wires should not be burnt due to over heating.

* Tap changera) contact

b)Insulation

c)Operating parts

Connection wires

Tap changing operation

Contacts should not be over heated or melted.No damage on insulation should be noticed.Shafts should not be loose. Spring should not found discoloured or broken.Wire should be in place and tight. No over heating/melting should be noticed.During tap changing operation there should not be any discontinuity and operation shall be normal.

PRECAUTIONS DURING INTERNAL INSPECTIONWhen transformer is to be dismantled and active part to be inspected it is better to consult the manufacturer of the transformer.

Following points to be taken into account during internal inspectionItems Description/procedure

Weather conditions Avoid checking active part on rainy or when rain is forecasted. Inspection also to be avoided if relative humidity exceeds 80%.In case urgent inspection is required on a cloudy day make sure tarpaulin sheets available near the transformer

Active part exposure In general active should not be exposed to atmosphere more than 8 hours. It is recommended to fill up oil and drain oil next day for further inspection.If exposure is too much transformer is to be put on drying cycle. For more information on drying contact manufacturer.

Earthing of transformer

Switch of breakers and isolators of HV & LV. Earth bushing terminals. It is better to keep bushings earthed during all repair work.

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Confirm power supplies to alarm, trip and control circuits attached to transformer are switched OFF.

Suffocation Before entering the tank, confirm oxygen concentration inside the tank is sufficient (18%).

Clothes Wear the cloths that do not have metal buttons zips etc.Do not carry wristwatch, pen, coin and other articles, which are not required for internal work.

Tools Bring in those tools, which are absolutely necessary for internal inspection and work. When passing tools and other materials from out side to inside and from inside to out side signal the recipient.Tie tools with body or out side of the tank using strings/cotton tape.Record all items brought into the tank and confirm that they are taken out when the work is completed.

Inside lighting Lighting fixtures should be provided with bulb guard. Use of low voltage bulbs is recommended.

Prevention of parts falling into coil

Before removing any parts do not forget to lay cloth sheets/bags so that they will not fall into coil.

Marking of parts When dismantling parts mark them so that reassembly can be done properly. Removal and lifting of parts are to be done carefully so that even slightest damage to winding is not caused.

Internal check up Confirm that repaired / replaced parts have been installed at proper places.Check all bolts and other fasteners for tightness.Check inside thoroughly and make sure that tools, bolts, nuts, replaced parts, Insulation materials such as paper, cotton tapes, cloth bags, sheets, etc. are not left behind.

PARTS REPLACEMENTReplacements shall be made in accordance with the instructions given below. Replacements are to be carried out when any abnormality is noticed.

Part name Interval Remarks1. Oil in

diverterswitch.

Change oil when dielectric strength is 25 kV or less and neutralization value is 0.3 or more

It is recommended to replace insulation oil and purifying material every time inspection is performed on diverter switch although the measured values are with in allowable range.

2.Purifying material in on-line oil purifier

Replace the material when carbon is seen through flow sight at outlet of purifier or if oil pressure becomes 3.0 kg/cm2

3.Arcing contacts of on-load tap changer

Replace when thickness of even one arc proof metal becomes less than the allowable dimension.

Wearing of arc proof metal changes according to load applied. Therefore, replace-ment should be determined by wear amount and tap change over frequency.

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4.Oil pump bearings

When even one of the bearing fails after 7 or more years of operation, replace all bearings.

If a bearing is damaged before reaching its design life, replace only that bearing. If bearings whose life is beyond expectancy, replace all bearings.Grease up lubrication type bearings once a year.

5.Fan motor bearing

Non lubricating type When even one of the bearing fails after 3 or more years of operation, replace all bearings.Lubricating type When even one of the bearing fails after 7 or more years of operation, replace all bearings.

6.Pipes of water cooled heat exchanger

Corrosion in the cooling pipe differs according to water quality. Replacements interval therefore should be determined through negotiations with manufacturer according to degree of corrosion.

7.Flexible coupling

For rubber couplings, approx. 10 yearsFor metal couplings, approx. 30 years

8.Gaskets After 10 years operation, replace all gaskets.

9.Instruments and relays

Thermometer 10 yearsOil flow indicator 25 yearsOil level gauge 25 yearsBuchholz relay 25 years

PAINTINGThe transformer and its accessories should be touched up painted fully at an appropriate interval to prevent metal surface from corroding.

Items Procedure1.Touch-up painting during installation

The portions where paint film has been scrapped off during transportation and installation should be touched up before commissioning.

2.Painting schedule Painting schedule depend on the environmental conditions of the location where transformer has been installed. It is recommended that painting should be done when corroded portion occupies 0.5 to 1.0 % of the total area.

3.Selection of paint It is recommended to use the following paints for prime coating and finish coating.

Application Paint name Property

1.Prime coating Zinchromate primer

Excellent in anticorrosion and water proof

2. Finish coating Epoxy paint Excellent in acid and alkali resistant

Synthetic enamel Excellent in weather proof.

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4.Painting operation 1.Preparation before paintingWipe of oil and dust thoroughly with petrol or similar. If it is not done properly, paint film applied may peel off.If paint deterioration is not much, clean the surface and roughen the surface by sand paper so that paint film applied adheres tightly to the existing film. Then, apply the same kind of paint as the existing one to the roughened surfaceIf paint deterioration is too much, scrape of the paint film down to bare metal, and repaint the portion.When stepping on pipe, stepladder or ladder for painting operation, be sure to secure it properly.For rusty portion, remove rust thoroughly by wire brush or sand paper, and apply primer After the primer dries completely, apply finish coat onto it.Before painting, lay paper or vinyl sheet on concrete floor to prevent paint from dripping down to floor.Before painting, mask, sight glasses, nameplates, etc.2.Painting operationGenerally, finish coats applied one day after prime coat is applied.If painting to be finished quickly, use paints which dries quickly.When painting with spray gun, take special care to adjacent equipment so that they are not painted accidentally.When painting is done after rain or snow, be sure to remove water thoro-ughly from the transformer. If paint is applied to a wet surface paint film may be corrugated with air bubbles. This makes paint film to peel off easily

4.Painting operation Check up after paintingAfter painting, make sure all masking tapes are removed. If pressure relief device is wrapped with tape, it fails to operate. After removing masking tape, make sure that paint is not sprayed onto porcelain and instruments. If it is wipe it of f thoroughly. Do not use petrol or thinner to clean acrylic covers of the instruments. Wipe it off with dry cloth.

LONG-TERM STORAGETransformer and its accessories should be stored after assembled as specified, with all valves kept in same status as those during operation. In addition, electrical and mechanical protective devises should also be kept in the same status as those during operation.

Inspection during storageWhen the transformer is stored in a completely assembled status, the following inspection should be made during storage.

Items DescriptionTransformer 1. Make sure that bushings and conservator are filled with oil up to

specified level.2. Check various parts for oil leakage. For gas filled transformer, check if gas pressure is normal.

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3. Make sure that silica gel breather operates normally, and oil cup is filled with oil up to specified level.4. Check water drain valve of conservator for oil or water leakage approximately once in every three months.5. Make sure the conduits and ducts of accessories are not water soaked nor corroded.6. Check whether following protective devices are kept activated.a. Pressure release valve, b. Buchholz relay, c. MOG,d. Air cell abnormality relay

OLTC 1. Make sure that conservator of diverter switch compartment is filled with oil up to specified level.2. Operate space heater, as necessary, to protect motor driven operating mechanism from moisture condensation.3. Change over tap selector from lower limit to upper limit every three months by using motor.4. Measure water content and dielectric strength of oil in diverter switch compartment every two years.5.Operate on load purifier approximately every three months

Incase transformer is charged after long-term storage, confirm that there is no abnormality.

INSULATING OILTESTING

Items Procedure

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1.Test classification

1.1 test during installation1.2 Routine test during maintenancePerform routine tests as shown below:

Transformer type Test intervalAir cell type Once every 2 yearsNitrogen filled typeOther types Once a year

WATER CONTENT, BDV, DGA1.3 Precision tests during maintenance

Transformer type Test intervalAir cell type Once every 6 yearsNitrogen filled typeOther types Once every 4year

Remarks: For open type transformer check properties of insulation oil more often than specified for the first three years.2. Test itemsWater contentTan BDVResistivityNeutralization valueInter facial tensionFlash pointAppearance

2.Sampling procedure

1. Perform sampling in fine weather. Avoid sampling in rainy day.2. Sample bottle should be plugged dark glass bottle/ stain less steel bottle, which has been thoroughly cleaned, dried and airtight.3. Clean sampling valve with cloth, and pour out a little amount of oil. Confirm sludge and water are not contained in the oil. Wash the sampling cup more than twice with the same oil to be sampled, and sample in to the bottle. After sampling put identification label on the bottle.4. One liter of oil is required for routine tests and two liters for precision tests.

3.Test method

Water content Karl Fischer’s method IS 13567BDV IS 6792Neutralization value IS 1448 (p:2)Dielectric dissipation factor (Tan ) IS 6262Specific resistance (Resistivity) IS 6103 Inter facial tension IS 6104Flash point IS 1448 (p: 21)Sediments and sludge content IS 1866 Appearance IS 335

4.Criteria for oil deterioration

CriterionItems

Class Good Critical Bad

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kV!.Water content (ppm)

>220 10 11~20 >20

66 &132 15 16~40 >40<66 20 21~50 Free water

2.Break down voltage (kV/2.5mm)

>220 >60 60 ~ 50 <50

66 &132 >50 50~ 40 <40<66 >40 40 ~ 30 <30

3.Neutralisation value ( mg KOH/g)

All <0.03 0.3~ 0.3 >0.3

4.Dielectric dissipation factorTan at 90C

>132 <0.01 0.01~0.2 >0.2<132 <0.015 0.015~

1.0>1.0

5.Resistivity at 90C(ohm cm)

All >6 10¹² 6~0.110¹²

<0.1 10¹²

6.Inter facial tension(mN/m)

All >35 35~15

7.Flash point C All >140 DecreaseBy 10C

Decrease by15C

8.Sludge &sediments All Not detected

Traces Detection of sludge

9.Appearance All Clear Cloudy Cloudy

Good- Oil can be used furtherCritical- Deterioration started, more frequent tests are required.Bad –Oil to be purified / reclaimed

SITE DRYING OF TRANSFORMERSIn the event that internal inspection reveals signs of moisture in the transformer or prolonged exposure is made for repair, site drying may be required. If drying is determined to be necessary, one or more of the following method may be adopted.

1) Circulating hot oil.2) Circulating hot oil and Vacuum cycle3) Nitrogen purging4) Hot air blowing.

Hot oil circulatingThis method requires a high vacuum oil filter, which is capable to raise and maintain temperature of oil to 85C. During circulation top valves of cooler /radiator shall be closed to prevent cooling. Connect delivery of the filter to bottom filter valve and inlet to top filter valve provided diagonally opposite. Transformer temperature shall be kept at 75 C during circulation. Effectiveness of this method depends on keeping a constant high oil temperature. The oil may be circulated till the oil become dry. Dryness is indicated by good IR value, low tan and low moisture content in the Oil. During circulation transformer and external pipes shall be insulated to prevent heat loss.

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Hot oil Circulation and vacuumThe process is same as described above after keeping temperature of oil constantly for 24 hours, drain oil from the transformer quickly. Then transformer may be subjected to vacuum. After keeping under vacuum for 24 hours fill transformer with oil. If desired results are not obtained repeat this process till good results are obtained. This method is useful where moisture content of transformer is high. Effectiveness of this process depends on the quickness of oil draining and applying vacuum with out loss of temperature. The accessories and parts which will not withstand vacuum shall be removed from transformer before the process.

Nitrogen purgingThis is a cold method of drying. Oil from the transformer is drained while dry nitrogen is being admitted to the transformer. After keeping the transformer for 12 hours check dew point of the nitrogen. When dew point of nitrogen reaches close to -40 C drying process is completed. If dew point of nitrogen is higher pull vacuum inside the transformer and admit fresh charge of nitrogen. Repeat his process till good values are obtained.

Hot air blowingThis method is used when moisture content in the insulation is very high. Blowing hot air at temperature of 110 C into the transformer is the essential feature of this method. During the process IR value tan shall be monitored regularly. After completion of drying, fill oil under vacuum into the transformer. During hot air blowing tank shall be kept insulated. The volume of air required to obtain minimum drying time varies with the size of tank.

Following table gives an approximate volume of air required for various sizes of tanksArea of tank base(m²) 2.8 5.6 9.3 11.

614

Volume of air (m³/min) 28 56 85 114 140

Precautions while Drying-out

Never leave the transformer unattended during any part of the process. The transformer should be watched and observed.

Transformer top oil temperature should never exceed 850C. The maximum temperature of anything in contact with the oil should never exceed 900C.

Maintain log sheet. Use lagging to prevent loss of heat through the tank walls and effect of could draughts. Use proper ventilation to remove the moisture given off by the transformer oil.

Duration of Drying-out

1 to 6 days for 11 kV transformers 10 days to 30 days for 220 kV transformers 15 days to 40 days for 400 kV transformers

The drying-out process should be continued till the oil samples taken from the bottom of the tank and top of the tank have desired dielectric strength (Break-down value of 40 kV with 2.5

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mm-gap, cold) and the insulation resistance is of desired value. The actual time required will vary widely depending upon season, the size of the transformer, amount of moisture, the method adopted for the drying-out and capacity of filtering plant.

Procedure of Drying Out

1. Heat is applied gradually by one of the methods to maintain steady temperature of winding and oil at following values.Top oil temperature not to exceed 850C.Winding temperature not to exceed 950C.

2. During the drying out period (which extends from a few hours to several days). The following measurements are taken after every one or two hours.

Insulation resistance values of 60 second and 15 second Megger reading (alternatively 10 min. and 1 min. reading).

Winding temperature Oil temperature top Oil temperature bottom Time from the beginning of drying out.

The insulation resistance values are measured between each winding and earth, and also between different windings.

The drying and process has three distinct phases described below:

Initially the insulation resistance values fall down indicating that the moisture is getting released within the insulation.

After a few hours the insulation resistance reaches a steady value indicating that the moisture has been distributed within the winding. This phase lasts for several hours or days depending upon the size of transformer, amount of moisture and the method of drying.

In the final phase, the insulation resistance value starts increasing indicating that the moisture is being expelled from the transformer.

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In the first phase of dying-out, the insulation resistance reduces. This indicates release of moisture within insulation and oil. In the second phase, the insulation resistance is steady. In the third phase insulation resistance starts increasing indicating that moisture is being expelled.

BDV of oil samples is measured after every four hours. Drying out process is stopped when sufficient insulation resistance and Polarization

Index is reached during third phase the insulation resistance value (hot) is more than the specified value, during the rising mode of the drying-out process and the polarization index, dielectric strength of oil are satisfactory. (P.I. -1.3, BDV- 45 kV for one min.).

Water collected (cold-trap) measures 2-3 readings constant (say 50 ml per hour or so), one must conclude that the transformer is completely dried and the water collected is from atmosphere.

It is more dependent on individual judgment.Steps in Drying-Out of a Power Transformer:1. Preliminary preparation of the transformer, source of heat, measurements, etc.2. Arrange the set-up.3. Apply heat by one of the suitable means gradually.4. Take periodic reading of Clock time Temperatures of windings, body and air, ambient Insulation resistance values of 15 second Megger Reading and 60 second Megger

Reading. Winding Resistance (At the beginning and at the end).

5. Maintain steady temperature or specified value (winding temperature not to exceed 600C or 700C depending upon insulation class). Measure periodically the insulation resistance values.

6.Initially, during first few hours, the values of Insulation Resistance reduces even though the heat is being applied for Drying-out. Why?During initial heating period, the moisture trapped in the insulation in form of small globules gets released within the insulation. Hence the insulation resistance value starts reducing.

7. Intermediate Stage. After a span of a few hours (for a medium sized transformer having good condition) or a few days (large transformer or a wet transformer) the I.R. reaches a steady value. This indicates that the moisture has spread all over the insulation.

The input power is reduced to reduce the temperature rise.8. Rising Stage. After a few hours of steady value, the insulation resistance starts rising.

This indicates that the moisture has vaporized and is being expelled (released) from the winding. The input power is reduced further.

9.The drying-out process is stopped when the desired value of Insulation resistance (hot) and polarization index is reached. In case of large machine both the insulation resistance and the Polarization Index are equally important.

The Input power is switched-off.

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Note: Megger (Insulation Resistance Tester) is used formeasuringtheInsulation Resistance between winding and earth. Temperature Measurement is by thermometer or thermocouple or self-resistance method.Dry-out by Circulation of Transformer-Oil through Purifier (Filtering Plant): The modern method of drying-out of transformer consists of circulation of the transformer oil through oil filtering plant. The modern oil filtering and purifying plants are portable and have the following components:-- Vacuum tank, vacuum pump-- Heating Chamber, Heater-- Spray Chamber-- Centrifugal Blower-- Strainer-- Pumps for Circulation of Oil.

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SCHEMATIC OF A PORTABLE OIL FILTRATION PLANT

The oil from the transformer tank is circulated through the filtering plant for (i) removing moisture (ii) removing sludge, dirt and solid impurities.

While using the oil filtering plant for the purpose of drying-out; the thermostat of the filtering plant is set at out-let temperature of 900C. The oil is drawn from the transformer tank through a pipe dipped to the bottom of the tank. The outlet of the filtering plant is delivered back into the transformer tank at the top.The purifier (filtering plant) is operated continuously except for one hour per day for cleaning the cones of centrifugal type of filter-or-filter pads of the vacuum type filter.The paper insulation and pressboard material, which make up a significant proportion by volume of transformer windings, have the capacity to absorb large amounts of moisture from the atmosphere. The presence of this moisture brings about a reduction in the dielectric strength of the material and also an increase in its volume. The increase in volume is such that, on a large transformer, until the windings have been given an initial dry-out, it is impossible to reduce their length sufficiently to fit them on to the leg of the core and to fit the top yoke in place. CAUTION: The circulating current produces heat which exerts pressure on conductor insulation from inside and vacuum in the tank, external to the conductor insulation tries to pull out insulation. A close and precise monitoring of drying out process including temperature control is required to safe-guard against damage occurring on account of such phenomenon.

Completion of dryingAs soon as the drying is completed it is essential that the tank be immediately filled with dielectric liquid to cover the core and winding. Filling under vacuum is preferred. During entire

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drying out process regular readings of temperature and insulation resistance between windings and between windings to earth shall be recorded. As the drying proceeds the insulation résistance will fall due to increase of temperature and release of moisture. The resistance will then begin to rise, the rate of rise slowing down as the drying nears completion. When the insulation résistance flattens out to a constant value, the transformer has reached the maximum degree of dryness obtainable with the drying system being used.

Tan tests may be used instead of or in addition to insulation resistance tests for determining the progress of drying. Power factor will increase as the temperature increases, and then decrease as moisture is extracted, and flattens when drying nears completion.

TRANSFORMER MAINTENANCETo verify the health of the transformer, following activities may be conducted regularly and corrective actions may be taken, if test results are out of limit or alarming:

(A) Winding (B) Insulation (C) Bushing (D) OLTC

WINDING:FRA & SFRA------- Mechanical condition assessment of winding (Integrity of winding -

winding deformation).(Shock-log / Impact Recorder).Thermography ---- Hot spot in conductor joint.

INSULATION:(1) Solid Insulation (2) Liquid Insulation.

For solid insulation

• IR/AI/PI --- Insulation (DC)• Dielectric Discharge(Tan delta-Capacitance/DF-PF) --- Insulation (AC)• PD (Partial Discharge - inception voltage) --- Insulation (void)• DP --- Degree of Polymerization --- (paper, press board and wood)• Furan --- Oil (indirect for DP) --- Paper insulation• Step Voltage Test --- Insulation• Hydran --- Dissolved H2 and Hydro Carbons (H2&HxCy) – for RLA of paper insulation• RVM --- Recovery Voltage Measurements --- Paper insulation• DGA (Online/Offline) for transformer overall health.• MAP Analysis for degree of ageing of insulation.

For liquid insulationInsulating Oil:

The six oil screen tests:

Neutralization Number (Acid Number), Page 44 of 80

Interfacial Tension (IFT), Relative Density (Specific Gravity), Color, Appearance (Sediment), Dielectric Breakdown Voltage.

Oil purifying and filtration:

WINDING:FRA & SFRA------- Mechanical condition assessment of winding (Integrity of winding -

winding deformation) (Shock-log / Impact Recorder).Thermography ---- Hot spot in conductor joint.

SWEEP FREQUENCY RESPONSE ANALYSIS [SFRA]Sweep frequency response analysis (SFRA) is a diagnostic tool to detect the transformer mechanical integrity.

Transformers subjected to mechanical stresses during Transportation Short circuit faults near the transformer Transient over voltages such as switching, lightning, etc.

Mechanical Stresses cause Winding displacement or deformation Winding collapse in extreme cases Such mechanical defects eventually lead dielectric faults in the winding

Frequency spectrum analysis Effective diagnostic tool use to measure deterioration due to mechanical stresses. Short circuit due to line faults can distort, displace winding. If windings are merely displaced, Transformer can fail due to insulation abrasion, during

next Short Circuit. Low voltage signal is applied to different phases and current passing through neutral

analyze for frequency spectrum. All three spectrums are compared to determine any major changes. Above technique in

single or multiple is used to identify, confirm the fault location.

Transformers are made up of complex RLC networks.Any physical damage results in changes to these RLC networks.The RLC network offers different impedance path at different frequencies.The transfer function of each frequency is the measure of the effective impedance of the RLC network.Any geometrical deformation, changes the RLC network, which in turn changes the transfer function at different frequencies.

Each winding turn is linked to the other inductively or capacitive. Each winding exhibits a characteristic frequency response. Which acts as the finger

print. These changes gives an indication of the damage within trans.

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Any winding movement results in substantial changes in the values of L & C at the local level.

Any winding movement causes changes in the characteristic frequency response. These changes in the RLC networks is what we are looking for.

We all know three main elements in Electrical network

Resistance R ------------- Not vary with frequency Inductance L=2πfl ------ Directly vary with frequency Capacitance C=1/2πfc - Inversely vary with frequency The winding of every transformer has an unique RLC network depending on its

geometry, used materials and manufacturing. The frequency response analysis for transformer is a very sensitive technique for

detecting winding movement caused by loss of clamping pressure or by short circuit forces, in service.

A change of RLC network appears, it means a change of frequency response characteristics that can be identified by a comparative analysis with signature.

FRA consists of measuring the impedance of transformer windings over a wide range of frequencies and comparing the results of these measurements with a reference set.

Principle of FRATransformer is a complicated network of distributed inductance, capacitance & resistance (LCR network)

By the use of standard spectrum analyzer, sweep frequency sinusoidal source of approx. 2V RMS is applied across the winding terminals. For different range of frequency, the impedance is measured. The curve (Impedances versus frequency) becomes indicative to know the status of the winding. The other curves for voltage ratio versus frequency are also used.

SFRA Capable of Detecting

When compared with signature results any deviation is an indicator of

Coil deformation (axial or radial), Core movements, Faulty core ground, Partial winding collapse, Winding deformations,

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Displacement, Hoop buckling, Broken or loosen clamps, Shorted turns & open windings.

FUNDAMENTALS OF SFRA

How does it work? A low voltage signal with varying frequencies are applied to the transformer. The input and output signal is measured. The ratio of the two signal gives the frequency response of the transformer. This ratio is called the transfer function from which the magnitude and phase can be

obtained. Each winding turn is linked to the other inductively or capacitive. Each winding exhibits a characteristic frequency response which acts as the finger

print. Any winding movement results in substantial changes in the values of L & C at

the local Level. Any winding movement causes changes in the characteristic frequency response.

In SFRA a steady sinusoidal input applied to a test object and measured output, Sweeping through the frequency range

The ratio of Vout / Vinput indicate frequency response For Analysis this Ratio converted in to graph DB V/S frequency

o by using formula DB = 20 logl 0(V out/ V input )Each 20 dB drop means we are looking at a tenth of the previous Vout / Vin dB ResponsedB's: as impedance increases, Vout falls

Measured responses are analyzed for any one of the following key indicators:

Starting db values ( -30 to -50 db for HV winding and -5 to -15 db for LV winding) the expected shape of a star and delta configuration

comparison of responses to fingerprint comparison of responses to the different phase of the same transformer comparison of responses to sister transformer creation of new resonant frequencies and the elimination of existing resonant

frequencieso Interpretation strategies

Different frequency bands of the SFRA trace relate to different elements within a transformer as under.

Band Likely Causes of Variation< 2 kHz Core Deformation, Open Circuits, Shorted Turns & Residual 2 to 20 kHz Bulk Winding Movement Relative to Each Other, Clamping 20 to 400 kHz Deformation Within the main and tap windings400 kHz to 2 MHzMovement of main and tap winding Leads; axial shift

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The bands overlap and are not well defined, the band limits are not strictly set and vary both with manufacturer and transformer MVA and voltage.

Hard and fast rules are difficult to generate as there are so many designs and manufacturers.

If DC testing was performed the core must be demagnetized before SFRA measurements

Measurements must be made at the tap position such that full winding take under test.

Transfer function (Vo/Vi) is measured for three frequency ranges:

Low frequency range 50 Hz to 2 kHz Medium frequency range 50Hz to 20 kHz High frequency range 5 kHz to 2 MHz

A GUIDELINE FOR THE ANALYSIS OF SRFA HAS BEEN IN EXISTENCE FOR MANY YEARS

2 khz scan is sensitive to core deformation, open circuit, shorted turns and residual magnetism.

20 khz scan is sensitive to mainly bulk winding movement and clamping structure. 200 khz scan is sensitive to deformation within the main and tap winding. 2 Mhz scan is sensitive to movement of main and tap winding leads.

DIFFERENT FREQUENCY BANDS HAVE DIFFERENT SENSITIVITIES TO DIFFERENT MECHANICAL FAILURE MODES.Interpretation:

Condition assessment is based on comparison of the present signature with the earlier patterns obtained on the same winding under healthy condition.

Comparison of responses of different phases of the same winding at the same tap position.

Comparison of responses of different transformers of the same design.SFRA MEASUREMENTS ARE PERFORMED UNDER THE FOLLOWING CONDITIONS:

On all new transformers for fingerprinting purposes. After relocation. After long duration short circuits. After any type of maintenance. Sfra measurements are performed on the lowest tap position.

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An additional measurement is made on the faulty tap position.

There are two method of injecting the wide range of necessary frequencies: Impulse response method: - Inject an impulse into the winding.Advantage of this method is the shorter measurement time.Swept frequency method: - Make a frequency sweep using a sinusoidal signal.Advantage of this method are:

o Better signal to noise ratio.o Equal, or near equal, accuracy and precision across the whole measurement range.o Less measuring equipment is required.o Wider range of frequencies are injected.

Impulse FRA vs. Sweep FRA

Impulse FRA Injects a pulse signal and measure response Convert Time Domain to Frequency Domain using Fast Fourier Transform (FFT)

algorithm

Low resolution in lower frequencies

SFRA Injects a single frequency signal Measures response at the same frequency No conversion High resoultion at all frequencies

Impulse FRA

Summary / conclusions SFRA is an established methodology for detecting electromechanical changes in power transformers. Collecting reference curves on all mission critical transformers is an investment. Ensure repeatability by selecting good instruments and using standardized measurement

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practices.

Thermography and UltrasonicsBoth are used as on line non contact methods of monitoring electrical assets. Can support each other and also each technology can provide specific information.Thermography cannot detect CORONA, because it does not produce heat, ultrasonics can due to the noise produced by electrical discharge of the corona (detection of sound above 20 kHz range). The type of sound recorded, determines the type of electrical disturbance. Sound levels are recorded in a % of dB. Thermography and ultrasonics testing are done together, so the plant conditions are same.

Thermography These temperature measurement method is non contact & nondestructive, so it is useful for inspecting energized electrical systems without any interruption in normal operation and detect a variety of potential faults. - Infrared Thermometer - Infrared Thermal Imaging System Infrared is an invisible portion of the light spectrum extending from 0.75 to 1000 microns.

Thermovision scanning (practices): -Thermo vision scanning done with thermo vision camera is an effective tool to identify hot spots in the conductor joint, loose nut and bolts and other hardware connections. The accurate results can be obtained if the scanning is done from the top using helicopter. However due to non availability of helicopter and also being expensive, scanning is done from ground.

Principle of operation:All objects above absolute zero (0 K or 275.15 deg C) emit infrared radiation. These Infrared energy is invisible to the human eye and the Infrared energy emitted from surface is proportional to its temperature. The sensor measures the amount of infrared energy emitted from an object and converts the incoming radiation into an electrical digital signal or temperature readout.Heat transfer by way of conduction, convection & radiation. All objects emit heat energy by infrared radiation. Detector of Thermal Imaging radiation to an electrical / digital system converts incoming signal and display visible image on LCD Screen.

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Thermal Imaging (Thermography) Infrared Thermal CameraCLAMPS AND CONNECTORS:Hot spots on clamps and connectors are taking big part of maintenance activity. Hence infrared thermo vision tool is used to detect hotspots. Thermal distribution profile becomes basis of analysis. Main advantage of this is to find deteriorating component prior to catastrophic failure. Measures adopted for hot spots.

CONTACT RESISTANCE MEASUREMENT:All electrical connections should be tight, contact surface clean & have perfect contact matching. lmproper connection offers resistance to the flow of current. Use Bimetallic joints, in case of aluminum to copper contacts. Metal oxides are formed on the contact surface in humid environment and offers resistance. Looseness can be due to vibrations, elect & thermal stresses. Joints can be monitored by measuring contact resist. Temperature rise is observed in case of improper contact & monitored by infra red Camera (Thermographs).

ON LINE HOT SPOT MONITORING:It indicate actual hot spot temperature of winding. Fiber optic hot spot sensors are embedded in the transformer winding at the manufacturing works at predecided locations. It requires accurate thermal model to predict correctly and locate sensors at appropriate location.Thermo vision:It is temperature contour. It indicates temperature gradients in different color.

FOR SOLID INSULATION IR/AI/PI --- Insulation (DC) Dielectric Discharge(Tan delta-Capacitance/DF-PF) --- Insulation (AC) PD (Partial Discharge - inception voltage) --- Insulation (void) DP --- Degree of Polymerization --- (paper, press board and wood) Furan --- Oil (indirect for DP) --- Paper insulation Step Voltage Test --- Insulation Hydran --- Dissolved H2 and Hydro Carbons (H2&HxCy) – for RLA of paper

insulation RVM --- Recovery Voltage Measurements --- Paper insulation DGA (Online/Offline) for transformer overall health.

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MAP Analysis for degree of ageing of insulation.

D.G.A.What is D.G.A.?

The transformer undergoes electrical, chemical & thermal stresses during its service life which may result in slow evolving incipient faults inside the transformer.

Collectively these gases are known as fault gases, which are routinely detected and quantified at extremely low level, typically in ppm in DGA.

Most commonly used method to determine the content of these gases in oil using vacuum gas extraction apparatus and gas chromatograph.

Effective fault gas interpretation should basically tell us whether there is any incipient fault present in the transformer.

It is study of gases formed in the transformer oil. Decomposition of gases inside oil due to heating. It is a diagnostic tool helping to detect faults, by detecting abnormal changes in oil,

before Buchholz Relay responds. A quantitative analysis of all dissolved gases in the transformer oil. The gases generated under abnormal electrical or thermal stress which get dissolved

in oil. DGA is one of the most valuable diagnostic tools available. It is a procedure used to

assess the condition of an oil-filled transformer from an analysis of the gases dissolved in the cooling / insulating medium. It is a well established technique that is cost effective, providing essential information from a relatively simple, non-destructive test based upon oil sampling. Whilst the analysis is normally done in a laboratory, on-line devices are also available. The results reveal much about the health of the plant including its present condition, any changes that are taking place, the degradation effects of overload, ageing, the inception of minor faults and the most likely cause of major failures.

DGA is a powerful diagnostic tool for predicting internal condition of transformer.

Reasons for evolution of gases in oil

De-polymerization Carbonization Pyrolysis [Ageing factors of transformer:- Pyrolysis (Heat), Hydrolysis (Reaction with

water), Oxidation (Reaction with O2)] Corona Arcing due to clearance to the tank and to adjoining winding. Overheating of the joints in OLTC and brazed points.

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Power flow through with continuous arcing . Inter turn windings failure . Shield ring failure. Core bolt fault. Overheating due to inadequate cooling or sustained over loading. Low energy sparking or partial discharges.

Following gases are generally found dissolved in transformer oil: OXYGEN O2 NITROGEN N2 HYDROGEN H2 CARBON CO CARBON CO2 METHANE CH4 ETHANE C2H6 ETHYLENE C2H4 ACETYLENE C2H2 PROPANE C3H8 PROPYLENE C3H6

• The dissolved gases may be due to: Exposure of oil with atmosphere. Decomposition of oil due to thermal & elect. stresses. Cellulose material on account of incipient fault. Every type of fault generate different mixture of gas. Gases generated either by breakdown of cellulose insulation (paper) or oil.

Buchholz alarm or trip operates if the flow of gasses collected is sudden and heavy.

DGA is probably the most powerful tool for detecting faults in electrical equipments in service.

Over one million DGA analyses are performed each year by more than 400 laboratories worldwide.

Gases in oil always result from the decomposition of electrical insulating materials (oil or paper), as a result of faults or chemical reaction in the equipment.

In addition to these gases, the decomposition of paper produces CO2, CO and H2O, because of the presence of oxygen atoms in the molecule of cellulose.

Some of these gases will be formed in large or smaller quantities depending upon energy content of the fault.

For example, low energy faults such as corona partial discharge in gas bubbles, or low temperature hot spots, will form mainly H2 and CH4.

Gases are highly soluble in oil and will remain dissolved initially.

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Gases are formed inside an oil-filled transformer, in that various gases begin forming at specific temperatures. From the Gas Generation Chart, we can see relative amounts of gas as well as approximate temperatures. Hydrogen and methane begin to form in small amounts around 150 °C. Notice from the chart that beyond maximum points, methane (CH4), ethane and ethylene production goes down as temperature increases. At about 2500 C, production of ethane (C2H6) starts. At about 3500 C, production of ethylene (C2H4) begins. Acetylene (C2H2) starts between 5000 C and 7000 C. In the past, the presence of only trace amounts of acetylene (C2H2) was considered to indicate a temperature of at least 7000 C had occurred; however, recent discoveries have led to the conclusion that a thermal fault (hot spot) of 500 0

C can produce trace amounts (a few ppm). Larger amounts of acetylene can only be produced above 7000 C by internal arcing. Notice that between 2000 C and 300 0 C, the production of methane exceeds hydrogen. Starting about 2750 C and on up, the production of ethane exceeds methane. At about 450°C, hydrogen production exceeds all others until about 750 0 C to 8000 C; then more acetylene is produced. It should be noted that small amounts of H2, CH4, and CO are produced by normal aging. Thermal decomposition of oil-impregnated cellulose produces CO, CO2, H2, CH4, and O2. Decomposition of cellulose insulation begins at only about 1000 C or less. Therefore, operation of transformers at no more than 900 C is imperative. Faults will produce internal “hot spots” of far higher temperatures than these, and the resultant gases show up in the DGA.

Faults of higher temperatures are responsible to form large quantities of C2H4.

Finally it takes faults with a very high energy content, such as in electrical arcs, to form large amount of C2H2.

By looking at the relative proportion of gases in the DGA results, it is possible to identify the type of fault occurring in a transformer in service.

Several diagnosis methods have been proposed to identify these faults in service.

The first one was the Dorenburg method in Switzerland in the late 1960s, then the Rogers method in UK in the mid 1970s.

Variations on these methods have later been proposed by the IEC (60599) and IEEE.

Periodic analysis of gases present in oil can identify nature of faults & indicate health of transformer.

The most effective method, and one that is recognized by all transformer owners world wide, is the ANALYSIS of DISSOLVED FAULT GASES in transformer oil. Transformer oil is a chain of hydrocarbons, which breaks down in to lower molecular hydrocarbons, i. e. the fault gases upon application of heat energy, generated by all types of faults in the transformer. Different types of faults such as Partial Discharge, Over Heating and Arcing generate

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different levels of energy. When the oil is subjected to this energy, certain types of gases are produced, depending on the level of energy being imparted to the oil.

Insulating materials within transformers and related equipment break down to liberate gases within the unit. The distribution of these gases can be related to the type of electrical fault and the rate of gas generation can indicate the severity of the fault. The causes of fault gases can be divided into three categories;

These three categories differ mainly in the intensity of energy that is dissipated per unit time per unit volume by the fault. The most severe intensity of energy dissipation occurs with arcing, less with heating, and least with corona.

Gases are formed inside an oil-filled transformer, in that various gases begin forming at specific temperatures. From the Gas Generation Chart shown in next slide, we can see relative amounts of gas as well as approximate temperatures.

Hydrogen and methane begin to form in small amounts around 1500 C. Notice from the chart that beyond maximum points, methane (CH4), ethane and ethylene production goes down as temperature increases. At about 2500 C, production of ethane (C2H6) starts. At about 350 C, production of ethylene (C2H4) begins. Acetylene (C2H2) starts between 5000 C and 7000 C. In the past, the presence of only trace amounts of acetylene (C2H2) was considered to indicate a temperature of at least 7000 C had occurred; however, recent discoveries have led to the conclusion that a thermal fault (hot spot) of 5000 C can produce trace amounts (a few ppm). Larger amounts of acetylene can only be produced above 7000 C by internal arcing.

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The first one was the Dorenburg method in Switzerland in the late 1960s, then the Rogers method in UK in the mid 1970s.

Variations on these methods have later been proposed by the IEC (60599) and IEEE.

Periodic analysis of gases present in oil can identify nature of faults & indicate health of transformer.

The transformer core is normally insulated from tank and magnetic shields. Failure of this insulation lead to circulating currents in the core and local overheating. These defect is known as Fiot metal fault’. They produce predominantly Ethylene (C4H4) and Methane (OH4). Also significant amount of Hydrogen (H2).

Degradation of crimped or brazed connection between flexible cable and rigid winding conductor often leads to a local hot spot that will initially generate some 00, but later mainly Ethylene (C4H4) and Methane (CH4).

Repeated overloads or cooling system deficiency may often result in overheating of winding insulation and thermal degradation of insulating paper. This type of fault generates mainly Carbon Monoxide (CO). This type of degradation is irreversible and determines the transformer end of life.

DGA is indicator that there is a problem

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Carbon dioxide (CO2) Indicates a leak in a sealed tankCarbon monoxide (CO) Indicates insulation overheating

(Degradation of cellulose based insulation - i.e. Paper)Hydrogen (H2) Indicates developing faultsMethane (CH4) Indicates developing faultsEthylene (C2H4) Indicates developing faultsEthane (C2H6) Indicates developing faultsAcetylene (C2H2) Indicates developing faults

Online Monitoring of Dissolved Gases

Decomposition of gases inside oil due to heating Gases are mainly H2, CO, C2H2, and C2H4 etc. Gases generated either by breakdown of cellulose insulation (paper) or oil Online monitoring device for gases Detects deviation from the baseline and also monitors evolution of transformers

There are three fault types that can be found in transformers. They are Partial Discharge, Over Heating and Arcing. The gases generated by these faults are hydrogen, methane, ethane, ethylene, acetylene, carbon monoxide and carbon dioxide. There is one gas that is common to all fault types and that is hydrogen. If a fault develops in a transformer, hydrogen will be produced at a greater or lesser extent. Therefore if a monitor is designed around the measurement of this one gas and the level of this gas increases over time, a fault would be predicted.

These gases remain dissolved in the oil. Rising levels of concentrations of these gases indicate a developing fault in the transformer. The actual type of the fault can be identified by measuring the concentrations of each gas, and calculating the ratios of these gases with respect to each other. Diagnosis of the ratios is as per any of the established standards such as

Rogers Ratio method, Nomograph method, IEEE method, Dorenbugr method, Westinghouse method, etc.

Extraction of the dissolved gases from the oil is achieved through a most innovative method, using a specially designed and calibrated glass syringe. This method of gas extraction is called the shake test method. The analyzed results will serve as guidelines for future reference and for trending. Instrument also accepts inputs of the oil quality analysis such as Acidity, Dielectric Strength, Power Factor, Water Content, Interfacial Tension, Viscosity, etc. and analysis these results to notify the user about the quality of the oil and thereby assisting

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maintenance engineers to detect developing faults at an early stage, and enabling them to prevent a major failure of the transformers.

Analyzing Results: No immediate action is required if values of the gases are with in the values given table below, except for new transformers and for transformers with earlier test data are available.

Max. permissible values in ppm

Dorenburg technique of key gas method and roger ratio method are widely used.

DORENBURG KEY GAS METHOD:

Key gas method becomes applicable to transformer with developed faults where absolute values of key gases are considered. the key gases are Acetylene. Hydrogen, Ethylene and Carbon Monoxide.

FOLLOWING TABLE ILLUSTRATES THE NATUREOF FAULTS, WHEN KEY GAS IS ABNORMALLY HIGHKEY GAS NATURE OF FAULTAcetylene - C2H2 Electrical arc in oilHydrogen - H2 Corona, partial dischargeEthylene - C2H4 Thermal degradation of oilCarbon Monoxide - CO Thermal ageing of oil

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PERMISSIBLE CONCENTRATIONS OF DISSOLVED GASES IN THE OIL OF A HEALTHY TRANSFORMER:Since gases are produced in normal ageing also, the service duration of the oil has to be taken into account.

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GAS CONTENT IN OIL DUE TO

FAULT

Diagnostic Tests Interpretation

Key Gas RatiosH2 / CH4 [HYDROGEN / METHANE]C2H6/ CH4 [ETHANE / METHANE]C2H4/ C2H6 [ETHYLENE / ETHANE]C2H2 / C2H4 [ACETYLENE / ETHYLENE]CO2 / CO [CARBON DIOXID / CARBON MONOXIDE]

When cellulosic materials are heated above 100°C, they begin to generate characteristic degradation byproducts, some of which are oil-soluble. These can be sampled easily and used as indicators of aging. These types of tests are known as “indirect tests,” since they are not direct measurements on the paper.

There are two kinds of indirect tests for determination of cellulose degradation:

Dissolved gases-in-oil; and Furanic compounds-in-oil. It is observed that between 2000 C and 3000 C, the production of methane exceeds

hydrogen. Starting about 2750 C and on up, the production of ethane exceeds methane. At about 4500 C, hydrogen production exceeds all others until about 7500 C to 8000 C; then more acetylene is produced. It should be noted that small amounts of H2, CH4, and CO are produced by normal aging. Thermal decomposition of oil-impregnated cellulose produces CO, CO2, H2, CH4, and O2. Decomposition of cellulose insulation begins at only about 1000 C or less. Therefore, operation of transformers at no more than 900 C is imperative. Faults will produce internal “hot spots” of far higher temperatures than these, and the resultant gases show up in the DGA.

Whether the fault is serious and the equipment needs to be taken out of service for further Investigation.

DGA can identify deteriorating insulation and oil, hot spots, partial discharge and arcing.

The evolution of individual gas concentration & total dissolved comustible gas generation over time and rate of change are the key indicators of a developing problem.

Detects deviation from the baseline and also monitors evolution of transformers.

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N2 and O2 are indispensable for the evaluation of the transfomer condition

N2: Referenzvalue for the gas saturation.

O2: Very important indicator for the ageing process

When Oxygen reaches 10000 ppm in the DGA, the oil should be de-gassed and new oxygen inhibitor installed. High atmospheric gases (O2 & N2) normally means a leak. Oxygen comes only from leak and from deteriorating insulation.

Oxygen inhibitor: Should be tested every 3-5 years along with annual DGA test. Acids are formed that attack the insulation and metal. Oxygen inhibitor extends the life of transformer. The inhibitor currently used is DBPC (Ditertiary Butyl Paracresol). Oxygen attacks inhibitor instead of the cellulose insulation. The ideal amount of DBPC is 0.3 % by total weight of oil (which is given on transformer nameplate).

NOTE: Thermo siphon where activated Alumina is used is for absorption of moisture from oil.

On line D.G.A. Monitoring of Transformer• DGA is proven technique to know type of defect at incipient stage in Transformer.

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• It indicates condition at the time of DGA event.• It do not guarantee of status still next DGA event.• Fault may occur between the two DGA events.• Transformer remains unmonitored in-between. • On line monitoring bridges the gap between two DGA snap-shots.• Key gases are evolve with different fault condition.

Advantages of regular gas analysis • Advanced warning of developing faults.• Determining the improper use of units.• Status checks on new and repaired units.• Convenient scheduling of repairs.• Monitoring of unit under overload.• Taking routine oil samples from the transformer is an extremely cost efficient way of

monitoring its fault gas concentrations under normal operation.

CONCLUSION & REMIDIES: It was decided to inspect the transformer thoroughly from inside. Transformer shutdown was taken & after draining the oil transformer inspected from inside. One connection of OLTC found loose. Bolt carbonized & deteriorated. Bolt replaced & joints were tightened & after filling & filtration of oil, transformer was taken into service. The problem was solved.

FUTURE DEVELOPMENTSProposed changes in DGA laboratory procedures have been noted above. IEEE Guide 57.104 was last revised in 1991 and is currently being revised once more. The committee is proposing a two step process for utilization of DGA laboratory data. The current thinking is that there should be one set of criteria of interpretation of the first DGA result and a second set of criteria for subsequent tests. Current deliberations include the concentrations of fault gases that will be classified as “normal” and levels that lead to a recommendation to monitor the transformer at shorter intervals. Once it is determined that one or more gases have exceeded these normal levels, then the rates of fault gas generation should be determined.

MAINTENANCE CONTROL BY DISSOLVED GAS IN OIL ANALYSISAs an effective means of controlling the maintenance of oil immersed transformer, DGA has been employed extensively.

Recommended values of gas concentration (IEC60599) unit-ppmTransformer type H2 CO CO2 CH4 C2H6 C2H4 C2H2Power transformer 60-150 540-

9005100- 13000

40-110 50- 90 60- 280 3- 50

Power transformerwith communicating OLTC

75- 150 400- 850

5300- 12000

35 -130 50- 70 110- 250 80- 270

Furnace transformer 200 800 6000 150 150 200 *Page 63 of 80

Distribution trans. 100 200 5000 50 50 50 5ANSI (IEEE C.57.104)Three levels are set as shown below as a means of expressing level of abnormality.

Judgment level content

Warning level I Unit-ppm

TCG H2 CH4 C2H4 C2H6 C2H2 CO500 400 100 10 150 0.5 300

If any of the gases exceeds these levels except C2H2. If C2H2 >0.5 transformer moves to warning level II.

Warning level II 1.C2H2 0.5 ppm2.C2H4 10 ppm and TCG 500 ppm

Trouble level 1.C2H2 5 ppm2.C2H4 100 ppm and TCG 700 ppm3.C2H4 100 ppm and TCG increment 70 ppm/month

The values given above are indicative only. Detailed evaluation may be carried out in reference with IEC 60599/ IEEE C.57.104

DIAGNOSIS FOR TRANSFORMER DEGRADATION BY DGAA Power transformer has a service life depending up on the degree of degradation of insulating materials. The components mainly serve as an indicator are CO + CO2, furfural, acetone etc... By measuring these quantities in oil operating life of transformer can be estimated.

Degradation Component Warning level Trouble levelCO + CO2 0.2 ml/g 2.0 ml/gFurfural 0.0015 mg/g 0.015 mg/g

INSULATING OILThe mineral oil in an oil filled transformer fulfills four functions that contribute to the operation of the transformer.

(1) Oil provides dielectric strength - acts as a dielectric and insulating material.

(2) Oil provides heat transfer - acts as a cooling medium.

(3) Oil protects the solid insulation - acts as a barrier between the paper and the damaging effects of oxygen and moisture.

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(4) Oil can be tested to give an indication of conditions inside the equipment - acts as a diagnostic tool for evaluating the solid insulation.

As oil ages, the ability to fulfill some of these functions reduces. Transformer oil is hydrocarbon product; mainly oil contains napthanic, parrafinic and aromatics.Naphthenic base transformer oil is more stable compared to others. Today we are going to discuss transformer oil terminology and then testing of transformer oil in details.

MONITORING OF OIL IS ALSO VITAL TO ESTIMATE THE REMAINING LIFE OF TRANSFORMER BY ENSURING THE QUALITY OF TRANSFORMER OIL PERIODICALLY.

Oil protects the paper from the effects of heat, oxygen and moisture. As the oil ages, reaction products form in the oil and paper. These reaction products are very aggressive towards the paper and actively tear it apart, molecule by molecule. This drastically reduces the mechanical strength of paper. Aging of the oil does not affect fulfillment of “Diagnostic Tool” function.

RELEVENT I.S. FOR TRANS. OIL

IS 335-1971-1983-1983A-1983B-1983E-1983FIS 1448-1967-1970-1976-1977 IS 6103-1971 IS 6104-1971IS 6162-1971IS 6262-1971IS 12177-1971-1987IS 1866 - 2000 (for used oil)Deterioration of oil begins from the moment it is filled in the transformer due to ageing and oxidation. The oil produces undesirable products like acids, sludges, moisture, etc. The transformer oil is liable to deteriorate under normal operating conditions. In some applications oil is in contact with air. It is hence prone to oxidize. Accelerated by the presence of catalysts. Consequently, the oil darkens in colour and the acid in it begins to increase, thereby increasing sludge and consequently causing other electrical properties such as dissipation factor tan to increase, ultimately hindering the life of transformer.

Oil ages because it oxidizes. The hydrocarbons in the oil react with dissolved oxygen to form oxidation by-products in the oil; we mean oils decay products, oxidation products, oxidation compounds, or ageing by-products in the oil.

The rate of oxidation proceeds faster in the presence of higher water content.

IS - 335 SPECIFICATION

APPEARANCE: Clear transparent and free from suspended matter and or sediments.

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• DENSITY: IS -1448 P(16) hydrometer/thermometer

DESIGN VALUE: 0.89 gms/ml @ 29.5° C max

• KINEMATIC VISCOCITY: IS -1448 P(25)

CONSTANT TEMPERATURE BATH THERMOMETERS / STOP WATCH

DESIGN VALUE - 27cSt @ 27° C max

• INTERFACIAL TENSION: IS - 6104

INTERFACIAL TENSIO METER

DESIGN VALUE - 0.04 N/M max

• FLASH POINT: IS - 1448 P(21)

Sudden drop in flashpoint is indicative of unsafe working condition of transformer.

By some reason temperature of trans. increases up to a point where oil emits excessive vapour and when mixed with air, ignitable mixture can cause flash on application of small pilot flame.

Two methods for safeguarding trans. and oil – (i)controlled temperature and (ii)use of oil, which does not emit vapour at that temperature. Value - 140 deg. C minimum.

PENSKY MARTINS CLOSED CUP FLASH POINT TESTER/THERMOMETERS.

DESIGN VALUE - 140° C min

• POUR POINT: IS - 1448 P(10)

Lowest temperature as a multiple of three deg. C when starts flowing. At lower temp., oil can freeze hindering formation of conventional current thereby reducing cooling ability of oil. May block Buchholz Relay operation. Must remain mobile - must have and retain viscosity. Value - minus 30 deg. C. max. (As per latest IS 335, it is minus 6 deg. C).

CLOUD POINT&POUR POINT APPARATUS/THERMOMETERS:

DESIGN VALUE - -6° C max

• NEUTRALIZATION VALUE: IS - 1448 P(2)

CONICALFLASKS / BURETTES / MEASURING CYLINDERS / BURETTE STANDS / VOLUMETRIC FLASKS

DESIGN VALUES -

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A. TOTAL ACIDITY: 0.03mgKOH/gm of oil

B. INORGANIC ACIDITY: NIL

• ELECTRIC STRENGTH(BDV): IS-6792

BDV TEST SET

DESIGN VALUES -

A. UN FILTERED: 30 kv / min

B. FILTERED: 60 kv / min

• DIELECTRIC DISSIPATION FACTOR (TAN DELTA): IS - 6262

TANDELTA TEST SET/OIL CELL HEATER/OIL CELL.

This gives the exact method of evaluation of dielectric degradation.

WHAT ARE PERMISSIBLE LIMITS?

o Ideally, Tan-Delta of insulation should be zero

o But in actual it has small loss (Ir) component.

o It is trend test and value of Tan-Delta is to be compared with previous value.

Transformer winding:

o NEW: 1 % is Max. permissible value

o IN SERVICE: 2 % is Max. permissible value

P.F is the ratio of power dissipation in oil to VA in oil when subjected to sinusoidal wave. (Measured at 50 Hz and corrected at 20 deg. C.)

àValue should be as low as possible to ensure non-presence of moisture, polar compound or other soluble impurities.

àHigher P.F. results in higher heating, corrosion and faster rate of oxidation.

àThis test provides protection against inferior oil -- cannot be achieved by measuring dielectric strength. Values (Range), 0.001 to 0.003 at 900 C, could be as high as 0.1 (for very old used oil).

àFor voltages above 145 KV, if it exceeds 0.2, oil needs replacement. For voltages below 145 KV, tan delta can be as high as 1.0. If it increases, resistivity decreases. Best way is to compare with previous readings. Deviation should not be more than 20%.

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àMeasuring instruments should be perfect.

Ir/Ic or Vr/Vc is the oil P.F.

DESIGN VALUE: 0.002 max

• RESISTIVITY:IS-6013

Out of every ten transformers that burn, reasons remain unknown for at least nine. The operating engineer can make a guess based on available data derived from post fire condition. One reason of short circuit - Oil could have started conducting because of presence of water or perceptible material, which reduces resistivity by contaminating oil.

Resistivity is defined as the ratio of D.C. potential per cm. to current density in Amps per Cm. Square. Value 700 Giga Ohm Cm. at 90 deg. C. In service, transformer oil can have value as low as 13 Giga Ohm Cm. It should not be less than 0.1Giga Ohm Cm.

àResistance is temperature dependent.

RESISTIVITY TEST SET/OIL CELL HEATER / OIL CELL DESIGN VALUES

A. 1500*1012 Ohm-cm @27° C min

B. 35*1012 Ohm-cm @90° C min

• PRESENCE OF ANTI OXIDATIVE INHIBITOR: IS-13631

MEASURING CYLINDERS/PIPPETES/BURETTES/ BURETTE STANDS

DESIGN VALUE: NOT DETCTABLE

• WATER CONTENT: IS - 13567

AUTO MATIC KARLE FISCHER TITRATOR / WEIGHING BALANCE

DESIGN VALUE: 50 PPM max.

• CORROSIVE SULPHUR: IS - 335 ANNEX-B

Some transformers age faster than others. One of the reasons is excessive corrosion of metal parts due to presence of sulphur, which might not have eliminated at the time of manufacture.

Standard recommends freedom from sulphur.

PARTIAL DISCHARGES

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Transformer manufacturers have always tested their transformer to provide assurance that they will perform suitably in service. Some of the special tests are expensive. Also it cannot be subjected to destructive testing. Routine tests are carried during manufacturing to provide quality assurance. For large and high voltages Partial Discharge (PD) measurement was introduced to check the level of PD’s and to eliminate the source of discharges exceeding the established limits.

Specifications specify discharge limits and transformer manufacturers are consequently required to suppress all sources of discharges exceeding these limits.

Definition: A Partial Discharge is a localized electrical discharge that only partially bridges the insulation between conductors and which may or may not occur adjacent to a conductor. The third edition of IEC 60270 - 1997 develops:

• Requirements for measurements with digital PD instruments

• Checks for additional capabilities of digital measuring systems

• Guidelines to digital acquisition of PD discharge quantities

It can also be defined as a partial dielectric rupture in the insulating materials with-out complete flashover or breakdown. This will always occur if the pertaining stress exceeds a given value called limiting field strength (PD or electric discharges following ionization). It is a localized low-energy electric discharge in insulating materials. It occurs in contaminated defective insulation, in voids, flaws etc, at over stressed points due to excessive electric fields. These factors may cause ionization in cavities within solid insulation, gas bubbles in insulating liquids or along dielectric surfaces. Although involving small amounts of energy, the PDs may lead to progressive deterioration of the properties of insulating materials. Its measurement gives advance warning about possible failure. For EHV transformers, the measurement of PD is an important nondestructive method of testing which provides valuable information concerning the condition of the insulation.

PD LEVELS AND CRITICAL STAGES

Table: PD Level Examples and Their Two Critical Stages:

Classification to be developed to support caution and alarm levels

Critical Stages and Alarms

DIELECTRIC CONDITION

PD LEVELS (FOUND IN PUBLICATIONS)

CALFION LEVELS ALARM LEVELS

Defect free 10- 50 pC

First warning signal: q>500-1,000pC

First fault signal q>>2,500pC

Normal deterioration

<500 pC

Poor impregnation 1,000— 2,000 pC

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Long term destructive ionization

2,500 pC in paper >10,000 pC in oil

Signal of defective condition: q>1,000-2,500 pC

Critical Condition: >> 100,000— 10, 00,000 pC

Large (3—5 rrrn in diarrter) air! gas bubbles in oil

1,000— 10,000 pC

Paper moisture upto 3—4% and relevant level in oil

2,000 —4,000 pC and reduction of PD inception voltage by 20%

Causes of Partial Discharge

If the insulating materials dielectric stress is gradually raised, the PD’s start at certain points (weak) due to gas-bubbles, voids, impurities, moisture particles, etc. As the stress increases the PD electrical discharges occurs, whose duration is less than 0.1 microseconds.

The electric charge jumps / flows through the defect causing a local discharge which generates high frequency signal of several Mega Hertz even over 10 MHz.

Some conditions that cause PD’s in transformers are:

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• Improper processing or drying insulation

• Over stressed insulation due to lack of proper recognition of the voltage limitation of the Insulation

• High stress area n conducting paths which can be caused by sharp edges on either the conducting part or the ground plane

• Presence of moisture

• Non-uniform voltage stress distribution resulting In high stressing zones; • Gas bubbles in oil

• Solid impurities in oil

The role of PD’s in a transformer is a great concern, as it can affect both the performance and life of the insulation system. In case of transient voltages they manifest themselves as low-energy sparks with gas evolution which can impair the strength of the insulation structure. Power frequency discharge leads to burning of the solid insulation and decomposition of the oil. Persistent PD’s lead deterioration of Insulation properties and ultimately failure of the insulating materials.

EFFECTS ON TRANSFORMERS

In a transformer PD causes a transient change of voltage to earth, at every externally available winding terminal. The effect of PD in transformers are two fold:

• The ion and electron bombardment can be damaging to the Insulation and shortens the life of the transformer

• The transient currents produced due to partial discharges may interfere with electrical communications

The sources of PD In transformers mainly are:

• Delamination of pressboard

• Voids between glued components

• Bubbles due to gas evolution

• Moisture in solid insulation

• Free metallic particles

• Fixed metallic particles• Bad connection of electrostatic shields• Static electrification• Surface tracking

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Prediction of PD at the Design Stage:

Design of insulation system is a very important step for reliable operation of any type of transformers. Transformer designers’ aim should be to design and manufacture a PD free transformer. In practice, some amount of PD’s always be there; endeavour should be to minimize them. If the electric stress values below the PD inception levels do not result into ageing of mechanical strength of the pressboard. The designer shall take care of the following:

• Evaluation of electrostatic fields in the highly stressed zones of EHV / UHV transformers • Identification of insulation involved in the highly stressed zone; • Evaluation of PD inception and extinction characteristics

What is the best unit of PD measurement (IEC limits)?

• In micro-volts (60’s), dependent on the capacitance of the test object • In Pico-Columb (apparent charge), independent of the capacitance, but dependent on the voltage class of the test object • In Joules (energy), independent of the capacitance, and voltage class of the test object

Defect-Induced Insulation Degradation:

Partial discharge according to IEC 60270:

• Can be calibrated;• A defined defect will give smaller signals with higher voltage systems; • The dissipated energy; • Closer related to deterioration of insulation; • Does not differentiate between one large and several smaller discharges.

NEED FOR THE PD MEASUREMENTS Example of effective PD parameters for insulation contamination

Insulation Condition

Max. Pulse Magnitude, pC

Repetition Rate, ppC

PD Power,

Clean <30 25 - 30 <0.2 Fairly clean (after repair) 250 - 380 1 - 2 0.6 -0.9 Contaminated 300-400 120-150 50-90 Severe contamination 220 - 250 1000 - 1800 470 - 800

Energy, Power of PD’s Criteria

In HV and EHV transformers PD measurement is essential to: • Establish the intensity of PD at a different region of the transformer • Check the quality of the insulation fabrication• Assess the quality of components on the basis of PD• Assess the extent of interference with the communication circuits which may be allowed due to practical and economical reasons

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Testing is done according to IEC 76-3, giving the test voltages and the acceptance criteria. PD testing is an option in IEC 60076-3. The acceptance criteria for the dis-charge level set in a commissioning test is 300 / 500 pC measured at 1.5 Urn during a 30 minute period after a short time over stress to 1.7 Um• The PD measuring equipment is specified in IEC 60270 -Calibration, Dissolved Gas in Oil Analysis, IEC 60599 -H2 Measured during Service to Indicate PD.

MEASUREMENT OF PDs

Paper—oil insulation combination continues to be a major insulation system in the design of oil filled transformers. PD’s are considered to be hazardous for satisfactory operational performance of HV, EHV and UHV transformers. Therefore, PD’s test (in laboratories) detects the deterioration of the insulation system, and localized defects. PD’s measurement is a part of special tests for EHV transformers. Some companies specialize in on-site or on-line measurement using various methods.

During the discharge, the electrical energy is converted to other kinds of energy (Figure) mostly heat, light emission, mechanical waves, etc. Some electrical energy is converted into mechanical energy and radiated as sound. Electrical observations of the partial discharges have to be made at the terminals of the test object i.e. the bushing of the transformers therefore detection of the PD’s also be performed by acoustic means using detectors, on the outside of the transformer tank. Methods to be followed have been developed for locating PD’s through established standards like IEC and IS. These standards indicate the time sequence of the tests, application of test voltage and PD values.

To evaluate the discharges it is necessary to know the apparent charge, because the charge accessible in this condition Is the apparent transferred charge of the insulation which is determined by the measurement across the terminals. According to IEC publication 60270 the apparent charge is defined as follows:

“The apparent charge ‘q’ of a partial discharge is that, when if injected instantaneously between the terminals of the test object, would momentarily change the voltage between its terminals by the same amount as the partial discharge itself ”.

The value of apparent charge should not exceed the values specified in standards i.e. at: 1.3 Um / Root 3 with q=300 pC and 1.5Um / Root 3 with q=500pC.

PD Detection MethodsLow frequency methods according to IEC 270

(<1 MHz) can be calibrated:• Wide banded with Af f0/2 gives good time resolution • Narrow banded Af 3 kHz

HF and UHF methods cannot be calibrated: • Possibility for noise suppression • Can be wide or narrow banded • Spectrum analyzers often used for detection

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• Still possibilities for source recognition

Narrow band vs. wide band measuring systems: A narrow band system operates with a bandwidth of about 10 kHz or less at a certain adjustable time range up to 1 MHz (e.g. radio noise meters). With a narrow- band system there is a possibility to avoid disturbance signals from radio transmitters by adjustment of the tuning frequency, but it shall be checked that winding resonance in the transformers do not disturb the measurement, the tuning frequency is in the range of 100 kHz to 1 MHz.

A wide — band system utilises a relatively large ratio between upper and lower limit of the frequency band, for example: 50 to 400 kz. A wide-band measuring system is less critical as to the response for different pulse shapes at different terminals, but is more receptive to external disturbance noise viz, radio signals in test locations with-out electrostatic shielding. Band-stop filters may be used against radio transmitters. Identification of PD sources by comparison of shape and polarity of individual pulses is possible.

First and other Findings:

First findings:

Phase angle of discharge pattern: Sharp points tend to generate discharges centered around voltage peaks (Emax)

The pulse repetition rate is low for single large defect and high for distributed defects. The discharge level tend to be high (i.e. up to 1,000s of pC) for large injected bubbles. Polarity dependent discharges can be seen from the sharp defects bound to the electrode (asymmetrical geometries).

Temporal instability / burst behaviour is seen for many types of defects. Discharge on moist surfaces seem to vanish with time.

Other findings:

• Corona discharge in air can be differentiated from corona discharge in oil; • Discharge pattern vary with:

a. Stress levelb. ‘Ageing’ of the model c. Subgroup can be distinguished:

Enclosed type discharge Void (Bubble gas) Sharp protrusion Surface type discharge

LOCATION OF PDs:

Identifying the location of PD needs both skill and experience. Several methods are available for location of PD’s. Following methods have been developed for locating partial discharges:

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• Acoustic detection• Visual detection• Electrical location

The electrical location is the method based on analysis of electrical signals generated by discharges and transmitted to measuring impedances. For enhanced reliability of transformers in transmission network on-site measurement and location has become of increasing interest. For comparison with factory results, it is preferable to use electrical detection method at site.

1. Narrow-band method called NEMA method or Radio-interference method (RIV);

2. Wide-band information method i.e. Pico Coulomb.

Ultrasonic method

When a discharge occurs in an impregnated dielectric, it generates a pressure wave that travels through various media according to the laws of physics.

As stated earlier PD is commonly done by either the acoustic technique or electrical technique. The acoustical sensors based on the Piezoelectric effects are less expensive and the main advantage of the acoustic detection is that, disturbing signals from electric network do not interfere with the measurement. But the PD detection is possible within a radius of about 200 to 300 mm from the source. Since; the acoustic signals are attenuated by the medium / materials through which they travel. Hence, a number of acoustic sensors may be used which are distributed carefully around the transformer. Acoustic sensors can also be placed internally, using waveguides (ex. Fiberglass rods) to enhance the strength of the received signal, but the system is inexpensive and difficult to install.

The PD detection range for the electrical is larger. It covers a wider area, which includes for example tap changer and bushings. There is better co-relation between instrument reading and actual PD magnitude as compared to that with the acoustic method. However, the measured generally hampered by electrical interference signals from surrounding equipments.

PD Sources causing gassing in oil (according to Ukraine experience)

Associated with the Main magnetic flux 31%;

Associated with the Stray magnetic flux 41%;

Associated with Operative voltage 28%;

a. Floating potential, bad contacts 14%;b. Creeping discharge 14%.c. In many cases, operation of the suspicious units could be continued if the source of

PD is identified (closed loops sparking due to floating potential, reversible changes in insulation....).

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DAMAGES DUE TO PDs Depending on strength of discharge, duration for which it occurs and the site at which it occurs the deterioration takes place resulting in fast ageing and ultimate failure of the insulation. From the experiences and experiments of the insulation samples as indicated wide variety of partial pulses can be produced even on the same type of sample. Some of these pulses have high rates of rise and fall, others are relatively broad in shape have a pulse width of about 10 ms. Considerable attention being needed to analyze these characteristics. It is important to recognise the following aspects very carefully.• Detection of PDs • The level of PDs at discharge site• The energy involved in PD’s • Types of insulating materials where discharge occurs • Location of PD in the transformers• Ageing characteristics of the insulating materials due to the occurrence of PDs

Damage to Insulation System:

In point - to - plane gap wide range of discharge can occur:

• Micro-Amp discharge = X - wax, methane, H2 and CH2• One amp discharge = paper destruction, unsaturated hydrocarbon gases• Void can be created by bubble trapped in the insulation• Carbonized tracks on solid insulation is frequently observed. Stack of paper show better corona resistance than an equally thick pressboard sheet.

PD measurement as diagnostic tool: The CIGRE survey 2003 reported successful experiences with wide application of PD measurements for diagnostic, monitoring and quality assurance. Achieved sensitivity of electrical PD detection (better than 50 pC) shows a new opportunity particularly in verification of infield repair quality. The following purposes for PD measurements may be highlighted:

• In field, identification of causes of PD and discharges after DGA indicates problem • Sensing the condition of the transformer exhibiting symptoms of reducing dielectric margin (high moisture, particles contamination, etc,) • Quality assurance after repair and refurbishment • Ranking the units requiring repair • Assessment of the conditions of critical transformers• Core and coil assemblies • Bushings and OLTCs

Whereas PD measurements at a factory are basically quality assurance procedures, those in field serve as diagnostic tool. There are three main potential sources of PD generation in power transformers. The sources of PD can be associated with the operating voltage, with the voltage induced by the main magnetic flux, and with the voltage induced by a stray flux.

The relevant diagnostic characteristics are:

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• Apparent charge magnitude • Pulse repetition rate • Discharge power • PD signature• Fault gas content

Gas generation rate as a rate of degradation of insulating material i.e. a function of discharge power. Diagnostic techniques based on PD measurements shall advise the engineer how to distinguish between really dangerous problems (e.g. destructive PD in oil-barrier structure), and problems that do not affect the functionality of a transformer, to a dangerous extent and the equipment could be kept in service at least for some time. Service experience varies throughout the world, in some countries internal PD is rare while in others this problem draws a lot of attention. PD testing - it being electric (conventional / high frequency) or acoustic - serves the purpose of revealing more of the nature of the defect and its location. These methods are also suggested for continuous monitoring.

For solid insulation, following remaining tests may be performed needbase

• IR/AI/PI --- Insulation (DC)• Dielectric Discharge(Tan delta-Capacitance/DF-PF) --- Insulation (AC)• DP --- Degree of Polymerization --- (paper, press board and wood)• Furan --- Oil (indirect for DP) --- Paper insulation• Step Voltage Test --- Insulation• Hydran --- Dissolved H2 and Hydro Carbons (H2&HxCy) – for RLA of paper insulation• RVM --- Recovery Voltage Measurements --- Paper insulation• MAP Analysis for degree of ageing of insulation.

THE ON-LINE MOLECULAR SIEVE AVAILABLE IN THE MARKET TO DRY OUT POWER TRANSFORMERSPower and distribution transformers are some of the most important and expensive assets in a power network. Compared to other equipment, they are very reliable and require very little maintenance since they have no continuously moving parts. However, the insulating materials degrade with time in service, and ultimately determine the end of life of the transformer.In a free breathing transformer water can not only enter the insulation material through the natural expansion and contraction of oil as the temperature cycles, but water is a by-product of the breakdown of the long chain hydro- carbon glucose molecule as a result of thermal and electrical stress, as the transformer ages. Excessive moisture will saturate the insulation and increase its conductivity. At higher temperatures vapour, or free moisture can develop increasing the risk of partial

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discharge.

TRANSEC is an on-line molecular sieve, developed and manufactured in the U.K, that will continuously remove water from the oil and from the paper insulation in a power transformer. This process not only reduces ageing, but will improve the dielectric strength of the insulation, and increase reliability.

Features:

Economic and Low maintenance system that is easily installed and commissioned to a live transformer.

Uses oil as the transfer medium to extract water from the paper insulation, where 95% of water is retained.

Weigh-in, weigh-out following regeneration ensures control of exact amount of water removed during absorption cycle.

Integral in-line oil filter will trap particulate matter and improve the dielectric strength of the oil.

Can incorporate on-line monitoring of temperature and moisture in oil. CL3 Model for oil volumes above 10,000 litres. CL1 Model for oil volumes

below 10,000 litres. Midel 7131 can be accommodated although 3 phase pump is required.

Benefits:

Reduces the effects of ageing on Transformers Increases reliability and service life of transformers by continuously removing

moisture and fibres. Enables transformers to be run on higher load cycles with greatly reduced risk of

failure. Increases plant utilisation and will allow capital expenditure to be deferred.

TRANSEC SYSTEM

Moisture has a great influence on the life expectancy and the load carrying capacity of a transformer. Water is not only detrimental to the dielectric properties of the liquid and paper insulation system, it also decreases its resistance to ageing, and reduces the electrical and mechanical strength of the solid insulation. In general, the mechanical life of the insulation is halved for each doubling of the ppm water content; the rate of thermal deterioration of the paper is directly proportional to its water content.

The TRANSEC system has the capacity to remove up to 10 litres of water from a transformer, before saturation, by using insulation oil as the carrier. Plumbed into the oil circuit at high and low level, the zeolite molecular sieve material will chemically bond water molecules as the oil is pumped through the molecular bed. A 10 micron particulate filter will at the same time remove extraneous matter, such as fibres, which can become ionised, from the oil, improving its dielectric strength.

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TRANSEC will benefit transformers in different ways:

The New Transformer - A new transformer will leave the factory with a % moisture in paper figure of approximately 0.5%. If TRANSEC is installed from new, it will maintain the insulation at this level, removing only small quantities of water, but may more than double the design life of the asset, for a fraction of the cost of the new transformer.

The Operational Transformer - Has been in service for a number of years, but analysis on an oil sample shows water content of 20ppm at 50° C. Knowing the volume of oil, and the dry weight of solid insulation, the Piper graph will tell us that the % moisture in insulation has risen to 4%, a level at which threatens accelerated ageing, as well as a danger of partial discharge, or possibly free water in oil. TRANSEC should be used for a calculated drying programme to reduce this figure by 50%, but in any case not below 1.5%. In drying the transformer and maintaining it in this state, the life of the asset will have been extended by many years.

The Out of Service Transformer - Perhaps the most obvious target for TRANSEC is to keep an off- line transformer free from moisture, formed through condensation, during the natural ambient temperature cycle. When the transformer is called back into service, the oil must be dry and able to withstand the electrical stress when energized and put on load.

MONITORING MOISTURE AND TEMPERATURE

With TRANSEC, and a Vaisala HMP228 monitor, a trend of moisture and temperature can be established to maintain any transformer at a reduced optimum level of water content, giving the asset a longer life, and improving its ability to withstand incidents of high electrical stress.

When the input and output ppm levels at the TRANSEC unit converge, the molecular sieve material is saturated, and the cylinders need to be changed. TRANSEC (UK) Ltd offer a cylinder exchange service, as well as full installation, and commissioning. Each cylinder has a serial number, and the ‘as supplied’ weight recorded on our database. A direct comparison after saturation shows the quantity of water removed from that cylinder, and so the water removal process can be manage.

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