How does Water or Moisture affect Power Transformer Health?

Water has one of the most significant effects on the aging of paper and insulating oil in a power transformer by reducing the dielectric strength of the oil and physical deterioration of the strength of the paper at working temperature. It also sets up the process of hydrolysis which together with heat and an acidic environment triggers a self-sustaining paper degradation process [1].

Paper insulation and pressboard structures are cellulose based and are made up of glucose molecules linked together to form chains. The average number of glucose molecules in a cellulose chain can be measured as a “degree of polymerization” which for new Kraft paper is usually about 1200. The larger the chains the more mechanical strength is available to the paper [2].

However water molecules have the ability to split these chains shortening the length of the chains and thus reducing the associated mechanical strength.

The influence of temperature

Temperature is a major catalyst of this process and operating at elevated temperatures speeds up this process. It so happens that one of the by-products of this process is more water which then adds to the levels and over time it becomes a self-sustaining process. This is why the levels of water must always be maintained to acceptable levels as reaching a critical mass situation will result in rapid deterioration of the paper properties and invariably the life of the power transformer.

Sudden increases in operating temperature due to overloading combined with high water content in the insulation and dissolved particles in the oil can cause bubble formation. Bubbles coming close to energized parts like the windings can result in dielectric breakdown of the oil with related discharges that can seriously affect the transformer.

It is found that transformers with high levels of water that experience many high-loading events can cause the excess water from the paper insulation to move into the oil. This then results in the relative saturation of water being very high causing the formation of free water and this may also occur when a heavily loaded wet transformer rapidly cools down. The collection of free water affects the dielectric properties especially around the active parts resulting in discharges that can cause long term damage. Free water also causes rusting of the metal parts like the tank, pipes and radiators.

How is water formed?

The main sources of water contamination in a power transformer are:

·     Residual humidity remaining from factory drying process

The factory dry out process will attempt to remove a much of the water as possible but there will always be a certain amount of water remaining in the transformer. That is why the quality control process during winding installation, oil filling and dry out process is very important in maintaining low water levels.

·       Air from atmosphere during normal breathing

From the time the transformer leaves the factory it will start absorbing water from the atmosphere. It is important that steps are taken to reduce the exposure of the internals of the transformer to water. Usually transformers are transported without oil and are filled under pressure with Nitrogen or dry air. This must be maintained until it is ready on site for the oil filling process.

After the transformer is in service the use of desiccant drying is used for free breathing transformers. Most transformers are now installed with a conservator air cell / membrane which form a barrier to the external environment and prevents Air from entering the transformer. Leaks on transformers are another place where water can enter the transformer. Leaks must be identified as soon as possible and rectified at the next available opportunity.

      Byproducts of oil-paper decomposition

As part of of the decomposition of oil and paper the byproducts of the chemical reactions produces water.

Where is most of the water stored? 

Mineral oil usually has a much larger mass when compared to the paper insulation in a power transformer however water has a low solubility level in oil making majority (> 95 %) of the water to be located in the cellulose insulation.

Water usually exist many in three forms

Dissolved in oil - The amount of water dissolved increases with increasing temperature.

Attaching - to particles like dirt, fibers from cellulose and acids

As free water - which usually collect at the bottom of the tank. Free water forms when saturation is reached with the water dissolved in oil. It has the same effect as “raining” where free water is formed. Free water also enters the transformer from leaks or from the air.

How is the level of water measured?

Measurement of water from oil samples are in the range of a few parts per million (0-10 ppm being acceptable). However direct measurement of water in the cellulose is usually expressed in percentage and can range from 0.3 % to 6 % (less than 2% being an acceptable level for transformers in operation).

Another influence in the accurate measurement or estimation of water is the temperature of the oil at the time of the sample. Other influences are how the sample was taken, environmental conditions and contamination of the sample.

The water content in the cellulose provides a much more reliable value for condition assessment, as it is barely influenced by those parameters. A reliable method to measure water content in paper can be performed using a paper sample by applying Karl Fischer titration, or inferred by using frequency-domain spectroscopy. Unfortunately, sampling of cellulose for moisture analysis is a very difficult task as the solid insulation of a power transformer isn’t easily accessible.

Physical–chemical oil testing analysis is another common methods used to provide a general condition of water level in the oil. 

How to interpret water level measurements?

Oil Samples:

Oil samples analyzed in the lab usually produce results in ppm (parts per million) in oil. As a general rule of thumb the following can be used for assessment:

Limits (PPM)
< 10	Normal
10   Moisture < 20	Monitor Closely and Maintain
> 20	Oil processing / replacement required / investigated

Paper:

To assess the amount of water in the paper on can use relation charts from the oil samples to infer the estimated wetness of paper. The following chart can be used.

Oommen Curves for moisture regions [3]

There are many other variations that will provide similar assessments.

Limits (PPM)
< 1.5 %	Normal
1.5 % < Moisture < 3%	Monitor Closely and Maintain
> 3%	Dry out recommended

International Standards

The following international standards provide guidance on the assessment and measurement of water or moisture in power transformers:

IEC 60422 -  Mineral insulating oils in electrical equipment - Supervision and maintenance  guidance

References

1	Cropp M, “Energised Dry-outs”, Techcon 2003, Page 66, June-July 2003
2	R. D. Stebbins, D. S. Myers and A. B. Shkolnik, "Furanic compounds in dielectric liquid samples: review and update of diagnostic interpretation and estimation of insulation ageing," Proceedings of the 7th International Conference on Properties and Applications of Dielectric Materials (Cat. No.03CH37417), Nagoya, Japan, 2003, pp. 921-926 vol.3.
3	T. V. Oommen, “Moisture Equilibrium in Paper-oil Systems,” Proceedings of the Electrical / Electronics Insulation Conference, Chicago, IL, pp. 162-166, October 3-6, 1983

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The Importance of Proper Cooling of Power Transformers

The correct design and operation of the cooling system of a power transformer is very important to maintain the health of the transformer. The design and type of cooling is usually governed by the application of the power transformer and is influenced by power output, location and environmental conditions. The cooling system thus in turn affects the design of the transformer.  The primary purpose of the cooling system is for the efficient removal or transfer of energy created by the heating effect of losses within the power transformer (components like windings, core and structures), out into the environment.

The environmental cooling medium is usually air and/or water. The following are the different types of cooling configurations that may be used in oil filled transformers [1, 2]:

ON	Oil Natural
ONAN	Oil Natural Air Natural
ONWF	Oil Natural Water Forced
OFAN	Oil Forced Air Natural
OFAF	Oil Forced Air Forced
OFWF	Oil Forced Water Forced
ODAN	Oil Directed Air Natural
ODAF	Oil Directed Air Forced
ODWF	Oil Directed Water Forced

Naturally oil cooled method is usually used on smaller rated transformers and generally within 30 MVA, where the heat generated from the core and windings are large enough to allow for natural convection circulation of oil to cool the transformer.  The principle of natural convection arises when hot oil rises and the cold falls in an enclosed area resulting in organic circulation of oil. The cooling surface area can be increased by providing the cooling tubes or fins to improve the efficiency of cooling.

Transformers may also have forced air cooling by means of fans to allow for external air circulation. As the rating of transformers increase (usually greater than 60 MVA) the internal oil circulation becomes more of a requirement to allow for quicker transfer and removal of heat generated allowing the transformer to operate within the designed temperature rise. In this case forced oil circulation is used by means of oil pumps in the oil flow circuit.

Water cooling is usually used in Hydro plant applications where the transformers are located underground. The water cooling forms an open loop system with the oil circulation being closed loop. To prevent contamination of the oil with water the coolers are usually designed with either double finned or having and intermediate closed loop low pressure water circulation. Leak detection is usually provided. These configurations are presented in the diagrams below.

Failure Modes in the Cooling System

Cigre A2.49 [3] has highlighted the following Failure modes for the cooling systems. These are predominantly due to the wearing out of cooling system components. Other problems may be due to installation problems especially after maintenance activities. When this happen the two basic functions of the cooling system i.e. oil circulation and heat exchange are affected.

The failure of cooling fans usually affects the load of the transformer. Usually there are spare fans but if more than one fan is out of service there may be a need to reduce load so as to maintain the designed temperature rise of the transformer.  

Sometimes when maintenance work is carried out on the coolers it is possible for the fans being replaced to be connected in the wrong direction resulting in inefficient cooling due to recirculation of warm air causing elevated oil temperatures.

The failure of cooling pumps is another major problem especially of forced oil systems. This affects the flow and circulation of oil in the transformer windings and core resulting in ineffective heat transfer to the external environment. Pump failure usually results in elevated oil temperatures.

Again it can happen that after maintenance work pumps are connected in the wrong direction resulting in reduced heat transfer efficiency which affects the general cooling of the transformer.

Failure of the control circuit of the cooling system plays can affect the operation of the cooling systems where insufficient fans and pumps from the coolers are activated for the relevant loading. This will cause elevated oil temperatures.

In cooler radiators high level of particles and sludge formation may block cooling ducts, piping and flow paths. This affects the oil flow and which reduces the cooling efficiency. Oil-water heat exchangers can also be blocked on the water side due to deposits or corrosion causing decreased cooling efficiency.

Another common problem is when radiator valves are left in the closed position. This prevents oil from circulating within the radiators causing major heating within the transformer.

The low viscosity of oil can also affect oil movement in the convection process especially through the winding cooling ducts. The viscosity of oil is affected by dissolved particles and oil ageing by-products and is dependent on oil temperature.

Leaks are a significant problem in cooling systems usually at the interface points to the tank and ancillary components. These may be due to the effects of corrosion or aging of the insulation material like gaskets.

With the changing environmental conditions becoming more prevalent, elevated ambient temperatures may affect the heat transfer from the transformer to the environment. This is also a major problem with transformers located in enclosed areas (buildings) when the HVAC system fails. Also, very low temperatures (at zero degrees Celsius or below) can affect water cooling where the water can freeze.  

Sometimes, in summer months, high inlet cooling water temperature can affect the cooling capability of the coolers. This may occurs if the transformer was not properly designed for the environmental conditions.

Inspections and Maintenance

It is very important have an intense inspection and maintenance program to identify failures beforehand so that these can be proactively resolved without affecting the performance.

Infrared scanning is an important and simple tool that can be used to provide a relative difference in surface temperature enabling areas of elevated temperature to be easily identified. Infrared scanning is usually done when the transformer is on load. It is usually most effective when done on a transformer that has been returned to service where problems like a closed radiator valve being left closed.

Temperature monitoring is a standard monitoring that is provided on most transformers. The prime purpose is to measure the energy within the transformer and any abnormal conditions can be easily picked up especially with regards to the cooling system as it easily affects the average temperature of the transformer. The top oil temperature is usually represents the inlet temperature of the coolers and when compared to the outlet temperature a differential can be established. This can then be compared between coolers.

Cigre Working group A2.27 recommendations for Condition Monitoring Facilities recommended that the following temperatures should be available for condition monitoring [4]:

• Top oil – measure of the temperature of the oil at the top of the tank
• Bottom oil – measure of the temperature representing oil entering the bottom of the windings usually the cooler outlet temperature
• Cooler inlet oil – can be taken same as Top oil temperature
• Cooler outlet oil – measurement taken from the cooler outlet oil. In some transformer designs the bottom oil measurement can be used
• Cooling medium at inlet to coolers – a measurement representative of the temperature of the cooling medium (normally air or water) at the inlet to the coolers. In the case of an air temperature measurement, the sensor should be mounted in the shade. Air ambient temperature can be used if this measurement is not available. For water cooling medium a sensor or thermometer pocket should be included at both the cooler inlet and outlet
• Ambient temperature – Monitor the ambient temperature if the transformer is located in an enclosed area (building). This temperature must be alarmed for immediate investigation when the alarm value is triggered.

The Cooler Performance Index: D Temp (Inlet – Outlet) can then be derived by finding the difference between the Inlet and Outlet temperatures. The difference (delta) can then be compared between coolers or designed values, if available. Temperature deltas more than 30% of between coolers should be investigated further.

Oil flow is another important monitoring parameter. Forced oil (OF, OD) cooling systems have designed flow rates to provide the accepted temperature rise. Modern transformers usually have oil flow indicators or switches confirming oil flow. Analogue oil flow meters provide actual flow rates which can be trended. These can also be compared between coolers and any flow anomalies can be easily identified. Oil flow provided pumps can be compared with about 80% of oil pump nameplate or in pump manual (considering 20% oil flow reduction due to oil path hydraulic resistance).

  

Routine visual inspection of the transformer oil-cooling loop components should be performed as regularly as prudent but should not exceed 12 month frequency. All abnormal conditions must be rectified as soon as possible. This can be a non-expensive way of proactively picking up problems. Fans must routinely energised to verify proper operation, especially standby fans.

  

Sludge building up especially on older transformers can affect the flow of oil in the windings and piping. This must be monitored routinely by doing oil tests such as colour/appearance, acidity, dielectric dissipation factor (DDF), acidity and interfacial tension (IFT), which can provide indications of sludge components before visible sludge occurs.

References:

1.	IEC 60076-2	Power transformers - Part 2: Temperature rise for liquid-immersed transformers
2.	C57.12.00-2015	General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers
3.	Cigre WG A2.49	Condition Assessment of Power Transformers
4.	CIGRE, Technical Brochure 343	Recommendations for Condition Monitoring and Condition Assessment Facilities for Transformers

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Duvals Triangle Method

The Duval Triangle Method makes use of the three combustible gases CH₄, C₂H₄ and C₂H₂ that are transformed for representation in a triangular plot. The triangle is able to differentiate the fault types partial discharges, electrical faults (high and low energy arcing), and thermal faults (hot spots of various temperature ranges). Each point is derived from the percentage volume of the sum of the three gases. The triangle has a clockwise direction in terms of increasing percentage gas levels. Figure 1 presents the triangle with the definition of the six fault diagnosis regions [Duval1].

Figure 1: Duval’s Triangle [Duval1]

The Duval triangle is very useful in providing diagnoses when a fault condition is already identified due to fact that two of the three gases used (ethylene and acetylene) are products of high energy conditions. The conditions identified are partial discharges (PD), discharges of low energy (D1), discharges of high energy (D2), thermal faults of temperature < 300°C (T1), thermal faults of temperature 300°C < T < 700°C (T2), thermal faults of temperature > 700°C (T3).

One of the key challenges of this method is that there is no region in the triangle to indicate a normal ageing state for the transformer. Thus this method is not as effective in identifying a change from normal to defective state.

An updated version, the Duval triangle 4 is composed of the three gases H₂, CH₄ and C₂H₆ which is more specific for low energy or temperature (PD, T1 and T2) [Duval5]. The Duval Triangle 5 is composed of the gases CH₄, C₂H₄ and C₂H₆ which is formed more specifically for the identification of faults of high temperature to ascertain more information about thermal faults in paper and oil [Duval5]. 

Use the following link to the "Analysis" section to get the Duvals Triangle diagnosis of the oil samples. Enter the oil sample under "Sample 5" to get the diagnosis.

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Case Study - 390 MVA GSU Transformer [1]

Background [2] 

On the 15 May 2005 this 390 MVA GSU transformer failed. During the previous unit outage the transformer oil was purified to remove moisture. The transformer was initially commissioned in October 1971. In 1996 the transformer was involved in a coupling transformer incident with another unit and was sent to the repair facility for refurbishment in April 1997. It was reinstalled in February 2000 where it started to gas and was removed for an internal inspection revealing loose flexible connections. This was repaired on-site and returned to service.

The gassing continued slowly and the transformer was removed from service for an internal inspection at the transformer repair facility which revealed a fault on the HV winding crossover. This was repaired. The impulse test although acceptable revealed the absolute value of the C-phase (300 pico-coulombs). PD test results being higher than that for the A and B phases (200 pico-coulombs).

The transformer was then installed on 14 June 2004. Between September-December 2004 the on-line DGA indicated an upward trend. The unit was then shut down for the generator replacement project and the last sample was taken on 22 December 2004. The transformer was returned to service on 25 March 2005 before undergoing oil purification where it failed on 15 May 2005. After the failure the internal inspection revealed damage to the C-phase HV winding as depicted in figure 5.

Analysis

From Figure 6, the LEDT for the period 1991 to 1994 the oil samples remained in the Normal region until the first trigger on the 21 October 1994 with hydrogen being 12 ppm, methane 56 ppm and carbon monoxide 245 ppm. After the coupling transformer incident in 1996 the sample taken on the 11 September 1996, moved into the T2 region with hydrogen being 59 ppm, methane 197 ppm and carbon monoxide 322 ppm. Subsequent samples were all in the defective region T1/T2 and the trend was along the %CH₄ axis. The transformer was then taken out of service in April 1997 for repairs. 

The LEDT in figure 7 represents samples for the period 2000 to 2005. The trend recorded at the top of the triangle was in the second period (4 January 2000 to 13 March 2000) after the transformer was repaired. As can be seen from this LEDT the transformer was already in a bad state in the T3 fault region. The sample values at commissioning were 225 ppm hydrogen, 434 ppm methane and 112 ppm carbon monoxide. On-site internal inspection revealed loose flexible connections, which were repaired on-site and returned to service. The trend still progressed within the T3 fault region and finally the transformer was taken out of service on 13 March 2000 where the recorded values for hydrogen, methane and carbon monoxide were 166 ppm, 530 ppm and 27 ppm respectively. The transformer was sent to the transformer repair shop for repairs.

The transformer was then installed on the 14 June 2004 with the oil sample results in the Normal region but soon after as observed in figure 7 the trend started to move into the defective region. The oil was then purified in an outage in December 2004 where the sample taken before this on the 22 December 2004 revealed hydrogen, methane and carbon monoxide to be 14 ppm, 79 ppm and 226 ppm respectively. After the oil purification these values were 2 ppm, 2 ppm and 38 ppm accordingly moving the transformer state back into the Normal region. The next trigger was received with the oil sample taken on the 13 May 2004, a day before the failure.

Figure 8 indicates the R-value trends with the initial samples below the 0.13 limit. The first trigger out of this limit was 21 October 1994. The next trigger was on the on 11 September 1996 after the coupling transformer incident. The R-values thereafter remained in the defective region (T2), even after the transformer was reinstalled in January 2000 after the on-site repair. When the transformer was sent to the repair shop in 2004 the samples started in the Normal region but soon immediately moved into the defective region (T1). This was once again noted after the purification of the oil where it moved into the defective region almost immediately thereafter. 

Summary

In this case study the initial oil results recorded were in the Normal region and then progressed to T1 and T2 of the LEDT shortly after the coupling transformer incident. The LEDT was consistent with capturing these changes. An interesting observation is made in the period when the transformer was installed in early 2000 where the oil sample results were focused on the top of the triangle. These were for high levels of methane and moderate levels of carbon monoxide. However after the on-site repair and with the reconditioning of the oil the actual ppm values of the gases decreased but the oil samples still remained in the top region of the triangle indicating that the ratio of these gases was still the same but in lower ppm values. This interesting observation provides some indication that the LEDT maybe insensitive to fluctuations in the actual ppm values.  

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Case Study: Investigation into Combustible Gases in Selector of Tap Changer

The following report highlights the problem of the production of combustible gases in the selector of the tap changer of gen/motor transformer 1 at A Pumped Storage Scheme.  This may be caused either by abnormal arcing or a leak between the diverter and selector compartments.

INTRODUCTION

From the oil results in 2002 it was noticed that there was an increase in the level of combustible gases in the selector tank of gen/motor transformer 1. This gas level was monitored and a gradual increasing trend is noticed. However the gases fluctuate around a level that is above limits. Last year (September 2002) it was proposed that an internal inspection be carried out in the selector to identify a possible cause for the high gassing. Due to production reasons and an outage not being available it was decided to rather monitor the transformer with regular oil samples (weekly to three weekly) until the outage in April 2003 where an internal inspection of the selector and diverter compartment is carried out.

POSSIBLE CAUSES

The first possible cause highlighted has to do with the operating limits of the unit linked to the range of tap changing. The tap changer is operated at least twice a day across the change over tap 9 which would result in a small arc that could be the source of the combustible gases. Comparing the levels of gases on all the other units, Unit 1 is at an elevated level suggesting an area of higher levels of arcing. If this is the case we need to as soon as possible identify and sort the problem out before it develops into an electrical fault resulting in the failure of the transformer.

The second possible cause is that there might be a possible leak between the diverter tank and selector. The diverter because of its operation will produce high levels of acetylene and combustible gases. If there is a leak between these compartments there will be a migration of the gases into the selector. 

OEM INSPECTION

Inspection of the U2 tap changer at the Power Station was carried out due to suspected faults as a result of high combustible gases in the selector tank. The following is an explanation by the OEM of the cause. It must however be stressed that the level of the U1 gases are far above that experienced on U2.

BACKGROUND

The dissolved gas analysis of oil samples taken from the selectors of the generator transformers indicated hydrogen and acetylene values higher than normal. This initiated an internal inspection of the selector switch on Unit 2 in February 1999.

EXPLANATION (By OEM)

This inspection revealed some evidence of sparking on the changeover contacts of the selector. The operations of these transformers are somewhat different from the other generator transformers in the  network. The pumped storage operation requires generating and pumping modes using the same transformer. This then gives rise to frequent tap changer operations and also a different tapping range. Unlike other generating stations the tapping range includes the changeover position on a daily basis.

During the changeover operation the polarity of the tap winding is reversed. To allow this to happen the tap winding is disconnected electrically. When the reconnection takes place even when it is not under load, the capacitive coupling to the other windings on the same phase induces some voltage in this winding. The contact to which it then connects is at a different voltage and then a minor arc occurs when this contact makes. This only happens to the changeover contact and it happens in both directions – tapping up and down. It is better explained when referring to the rating plate diagram. 

Figure 1:

The changeover occurs on position 9.  9A and 9B are the transitional positions but have the same output voltage as position 9. This is where the polarity of the tapping winding is reversed. Consider the operation from tap position 8 to 10. The taps occur from 8 to 9A. Then to 10 via 9 and 9B without stopping on 9 or 9B.  At the point of 9 the tap winding is completely disconnected and then connected in the reverse polarity on position number 9B. When going back from position 10 back to 8 the actual arc takes place between position 9 and 9A.

MONITORING

After it was discovered that there is an increasing trend of combustible gases especially acetylene in the selector tank, special DGA sampling at weekly intervals were established. This was then increased to every three weeks when the level stabilised. While this was monitored the tapping profile was also recorded for 17/10/2002 to 4/11/2002. This information is discussed below. The next long outage on this unit was only planned in April 2003 and it was agreed that the tap changer be closely monitored until the outage or if there were further increases in the gas level to warrant an emergency outage. The oil results of the selector may be found in appendix 1 and the tapping profile data may be found in appendix 2. Figure 2 below clearly portrays the tapping profile of gen/motor transformer 1. As was explained in section 4 above the taps move across taps 8-10 crossing the transition tap 9 on most occasions thus producing a small amount of arcing which results in the production of combustible gases. 

Figure 2:

Figure 3 illustrates the number of taps that are changed per day for the period 17/10/02 to 4/11/02. The average number of tap changes for one day is estimated at 8 taps per day. This is considered to be frequent for a generator/motor transformer but not unusual considering its application.

Figure 3:

Figure 4 below gives an indication of the number of taps per mode. From this profile it is evident that most taps are during generating and SCO modes.

Figure 4:

TEMPERATURE & HYDRAN

Weekly oil and winding temperature readings taken reveal that gen/motor transformer 1 is also relatively and consistently warmer that its other three counterparts. This increase has been noticed from just six months now. The Hydran reading has also increased a bit to 162 ppm were it was previously sitting at mid 130’s. 

OUTAGE – APRIL 2003

During the outage in April it is proposed that an internal inspection be carried out to identify the cause of the high gassing. The monitoring of the gases over the past three months gives no indication of a decreasing trend. The risk of a possible failure would thus be considered high. If the internal inspection is not carried out in the April outage Peaking will have to live with the knowledge of a possible failure.

The oil samples taken for the past three months was taken to keep track of further increases so as pick up any problems as quick as possible. The hydran on the transformer is only monitoring the main tank which is isolated from the selector by a shut off valve. This further emphasises the need for this inspection. 

CONCLUSION

From the report above it is clear that there is an arcing problem in the selector of gen/motor transformer 1. We however need to establish the criticality and source of this arcing. The possibility of a leak between the selector and diverter must also be investigated so that plans can be put in place for the replacement of the diverter barrel if such leak exists.

It must also be noted that if the recommendations made below are followed it must be coordinated with the conservator bag project which is scheduled in the April 2003 outage due to interfaces on the handling of oil. 

RECOMMENDATIONS

The recommendations below can be implemented in the April 2003 outage.

1.  Inspect tap changer (selector & diverter) tank for source of combustible gases.

2.  Test diverter and selector to identify if there is a leak between selector and diverter tanks.

3.  If tap changer is scheduled for 18 month service, carry out the service.

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