TRANSFORMER OIL PRESERVATION SYSTEM BASIC INFORMATION AND TUTORIALS

Although transformer oil is a highly refined product, it is not chemically pure. It is a mixture principally of hydrocarbons with other natural compounds which are not detrimental. There is some evidence that a few of these compounds are beneficial in retarding oxidation of the oil.

Although oil is not a “pure” substance, a few particular impurities are most destructive to its dielectric strength and properties. The most troublesome factors are water, oxygen, and the many combinations of compounds which are formed by the combined action of these at elevated temperatures.

A great deal of study has been given to the formation of these compounds and their effects on the dielectric properties of oil, but there apparently is no clear relation between these compounds and the actual dielectric strength of the transformer insulation structure.

Oil will dissolve in true solution a very small quantity of water, about 70 ppm at 25 C and 360 ppm at 70 C. This water in true solution has relatively little effect on the dielectric strength of oil. If, however, acids are present in similar amounts, the capacity of oil to dissolve water is increased, and its dielectric strength is reduced by the dissolved water. Small amounts of water in suspension cause severe decreases in dielectric strength.

The primary reason for concern over moisture in transformer oil, however, may not be for the oil itself but for the paper and pressboard which will quickly absorb it, increasing the dielectric loss and decreasing the dielectric strength as well as accelerating the aging of the paper.

It is generally recognized today that the best answer to the problem of air and water is to eliminate them and keep them out. For this purpose, in American practice, transformer tanks are completely sealed. About three basic schemes are used in sealed transformers to permit normal expansion and contraction of oil (0.00075 per unit volume expansion per degree Celsius) as follows:


1. A gas space above the oil large enough to absorb the expansion and contraction without excessive variation in pressure. Some air may unavoidably be present in the gas space at the time of installation but soon the oxygen mostly combines with the oil without causing significant deterioration, leaving an atmosphere which is mostly nitrogen.

2. A nitrogen atmosphere above the oil maintained in a range of moderate positive pressure by a storage tank of compressed nitrogen and automatic valving. This scheme has the advantage that the entrance of air or moisture is prevented by the continuous positive internal pressure, and the disadvantage of somewhat higher cost.

3. A constant-pressure oil-preservation system consisting of an expansion tank with a flexible synthetic rubber diaphragm floating on top of the oil. This scheme has the advantages that the oil is never in contact with the air and there is always atmospheric pressure and not a variable pressure on the oil. The disadvantage is the higher cost. A number of mechanical variations and elaborations of this general idea have been devised.

It is now generally recommended that the constant-pressure oil-preservation system of item 3 be employed on all high-voltage power transformers (345 kV and above) and on all large generator step-up transformers. This is a consequence of unfavorable experience with transformers having gascushion systems, which inherently operate with large quantities of the cushion gas in solution in the hot oil under load.

If the oil is suddenly cooled (reduction of ambient temperature or load), the oil volume contracts and the static pressure of gas over the oil drops rapidly, allowing free gas bubbles to come out of solution throughout the insulation system. The dielectric strength of the oil and cellulose insulation system is drastically weakened when it has free gas inclusions, and this has occasionally led to electrical failure of operating transformers.

TRANSFORMER GAS IN OIL ANALYSIS BASIC INFORMATION AND TUTORIALS

Various research organizations, such as Westinghouse Electric Corporation, Analytical Associates, Inc., that did extensive research in the 1970s quickly led to the widespread use of dissolved gas-in-oil analysis as a predictive maintenance tool [4]. There is also an extensive bibliography on this subject found in IEEE Std. C57.104–1991 [5].

The basic theory is straightforward: Transformer dielectric fluids are refined from petroleum and are very complex mixtures containing aromatic, naphthenic, and paraffinic hydrocarbons. At high temperatures, some of these molecules break down into hydrogen plus small hydrocarbon molecules such as, methane, ethane, ethylene, acetylene, propane, and propylene. This process is known as cracking.

The kraft paper materials that are used to insulate transformer windings are made up of cellulose. At high temperatures, cellulose oxidizes to form carbon dioxide (CO2), carbon monoxide (CO) and water (H2O). High concentrations of CO2 and or CO are indications of overheated windings.

All of the breakdown products are gases that dissolve readily in transformer oil in different concentrations, depending on the specific gas and the temperatures that produce them. By taking samples of transformer insulating oil, extracting the dissolved gases and doing a quantitative analysis of the various gases in the samples through gas chromatography, it is possible to infer the temperatures at the sites where these gases were produced.

At temperatures below 150°C, transformer oil starts breaking down into methane (CH4) and ethane (C2H6). At temperatures above 150°C, ethylene (C2H4) begins to be produced in large quantities while the concentration of ethane decreases.

At around 600°C, the ethylene production peaks while the concentration of methane continues to increase. Acetylene (C2H2) production starts at around 600°C and methane concentration peaks at 1000°C. Hydrogen (H2) production is not significant below 700°C and continues to increase along with acetylene at temperatures above 1400°C.

Therefore, the relative concentrations of the key gases change over a wide range of temperature. This is basis for the application of dissolved gas in-oil analysis for predictive and diagnostic use. An approximate formula uses the ratio of C2H4/C2H6 to derive the temperature of oil decomposition between 300°C and 800°C:

T(°C) = 100 C2H4/C2H6 + 150

The so-called Rogers ratio method takes the ratios of several key gases into account to develop a code that is supposed to give an indication of what is causing the evolution of gas. The codes for the four ratio method are given in Table 8.2. A fairly detailed diagnosis of transformer trouble can be derived from various combinations of codes, shown in Table 8.3.

The diagnoses shown above were derived from empirical observation. The problem with the four-ratio Rogers code is that a code generated from the gas concentrations will often not match any of the ‘‘known’’ diagnoses.

So like a rare disease with strange symptoms, many cases of transformer trouble cannot be diagnosed at all using this method. Another method, called the three-ratio method, sometimes works when the four-ratio method does not.

In the three-ratio method, the values of A, B, and C are given in Table 8.4 with the corresponding diagnoses for the various combinations given in Table 8.5. Not only are the ratios of the key gases important, but the total quantity of dissolved gas and the rate of increase are also important factors in making a diagnosis. One of the criteria for making a judgment call is the total combustible gas concentration. The combustible gases include H2, CH4,

C2H4, C2H6, C2H2, which are produced by oil decomposition, and CO, which is produced by cellulose decomposition. Each utility has a different philosophy and a different threshold for concern.

Table 8.6 gives one set of guidelines based on good utility practice that is useful for determining the overall health of a power transformer based on the total concentration of combustible gases.

It is generally accepted that if the rate of combustible gas generation exceeds 100 ppm per day on a continuing basis, or if the presence of C2H2 exceeds 20 ppm, then consideration should be given to taking the transformer out of service to perform additional tests and inspection.

IEEE Std. C57.104-1991 Table 3 also provides a set of actions based on the total dissolved combustible gas (TDCG) concentrations as well as the daily rate of TDCG production.

According to the IEEE Guide, a rate of 30 ppm per day is the threshold for considering removing the transformer from service. Oil samples are taken from the bottom drain valve in a sealed syringe to prevent the dissolved gases from escaping.

The samples are sent to a chemical laboratory where the dissolved gases are extracted from the sample under vacuum and analyzed using a gas chromatograph. The results are reported as ppm dissolved in oil.

  

VACUUM OIL FILLING PROCEDURE TUTORIALS

1. Remove all oil from the transformer.

2. Test new, unprocessed oil for dielectric strength using ASTM Method D877. The oil must have a minimum breakdown voltage of 30 kV.

3. After assembly, pressurize the transformer to 2 psig by adding drynitrogen. Check the transformer for leaks.

4. For transformers rated 115 kV and above, after waiting for a 24 h period, make a dew-point check to determine the dryness of the transformer insulation. For new transformers and transformers in warranty, refer to the manufacturer’s instructions for acceptable dew-point readings.

For transformers not in warranty, refer to Table 8.1.5. If it does not pass dew-point test, a hot oil dryout is required. After dryout, repeat step 4.

5. Draw a vacuum of 2 mmHg or less. Hold this vacuum for a period of time specified in the manufacturer’s instruction book, if the transformer is new or in warranty. If the transformer is not in warranty, use Table 8.1.6.

6. Maintaining a vacuum of 2 mmHg or less, admit oil into the top of the transformer connection. Once oil filling is started, it must not be interrupted. Oil degassing equipment is required for transformers rated 115 kV and above.

7. If the transformer is a conservator type, stop filling when oil reaches a level 2 in. below the transformer cover. If the transformer is equipped with a nitrogen bottle, stop filling when the oil level gauge is slightly over the 25°C level. This is to compensate for the transformer expanding when vacuum is broken and for oil cooling.

8. Break the vacuum with dry nitrogen. If the transformer has a conservator with air bag, or air separation membrane, add the remaining oil to the expansion tanks in accordance with the manufacturer’s recommendations.

9. Bleed the air from transformer oil pump vents. Turn on all pumps and leave them running while the oil cools.

10. Allow the transformer to stand before energizing (with oil pumps running) according to the timetable shown in Table 8.1.7. Run one half of the pumps for half the time and the other half of the pumps for the second half of the time.

11. Prior to energizing the transformer, check oil levels in all compartments. Pump oil into the top, if necessary, to raise the oil level to the 25°C mark.

12. Prior to energizing the transformer, shut off all oil pumps and place controls on automatic so that no pumps are running prior to energizing. This is important to eliminate static electrification of the oil, which could cause an internal failure. This hold time must be a minimum of 12 h.

OIL IMMERSED TRANSFORMER INSULATION VALUE BASIC AND TUTORIALS

(Standard Handbook for Electrical Engineers), is depended on very largely to help insulate the transformer; this is done by providing liberal oil ducts between coils and between groups of coils, in addition to the solid insulation. The oil ducts thus serve the double purpose of insulating and cooling the windings.

Since the oil is a very important part of the insulation, every effort is made in modern transformers to preserve both its insulating and cooling qualities. Oxidation and moisture are the chief causes of deterioration.

Oil takes into solution about 15 percent by volume of whatever gas is in contact with it. In the open-type transformer, oil rapidly darkens, owing to the effects of oxygen in solution in the oil and the oxygen in contact with the top surface of the hot oil.

1. Expansion tank (or conservator). One of the first devices used to reduce oxidation was the expansion tank (or conservator), which consisted of a small tank mounted above and connected with the main tank by means of a constricted connection so that the small tank could act as a reservoir to take up the expansion and contraction of the oil due to temperature changes and reduce the oil surface exposed to air.

2. Inertaire transformer. This transformer has the space above the oil in the tank filled with a cushion of inert gas which is mostly nitrogen. The nitrogen atmosphere is initially blown in from a cylinder of compressed nitrogen and is thereafter maintained by passing the inbreathing air through materials which remove the moisture and the oxygen, permitting dry nitrogen to pass into the case.

A breathing regulator, which consists of a mercury U tube with unequal legs, allows inbreathing of nitrogen when the pressure in the case is only slightly below atmospheric, but prevents outbreathing unless the pressure in the case becomes 5 psi (34,474 Pa) higher than atmospheric pressure.

The elimination of oxygen from within the transformer case eliminates the oxidation of the oil and prevents fire and secondary explosion within the case.

POWER TRANSFORMER WATER IN OIL ANALYSIS BASIC AND TUTORIALS

There is an old expression, ‘‘Oil and water do not mix.’’ Thus, oil is not usually thought of as having a great affinity for water, and in fact it doesn’t. However, the kraft paper insulation found in most power transformers has a tremendous affinity for water.

In fact, cellulose is often used as a drying agent or desiccant. If there is moisture present in the transformer, it will usually wind up in the kraft paper insulation. Moisture not only weakens the insulating properties of the kraft paper, it also accelerates the rate of aging.

Therefore, in order to prolong the life of a transformer, moisture must be monitored. Since samples of the insulation cannot be taken while the transformer is in service, water-in-oil analysis is used to monitor the moisture content of the kraft paper as a surrogate.

There is a known equilibrium between moisture concentrations in the kraft paper versus the moisture concentrations in the oil based on the temperature of the paper and oil. The equilibrium is expressed by the so-called Piper chart, shown in Figure below.

Notice that as the temperature increases, water is driven from the paper into the oil. At elevated temperatures the oil is able to dissolve more water than at lower temperatures. The relationship can be expressed by the following equation.
T = 31.52 - 26.605 Ln pct + 17.524 Ln ppm

where
T =  temperature (°C)
pct  =  % water in paper
ppm = ppm water in oil

When doing a water-in-oil analysis, a syringe sample of oil is taken from the drain valve. Care must be exercised so that the oil is not exposed to the atmosphere. (Any exposure to the atmosphere will cause the oil to quickly reach equilibrium with the air.

Since ambient air usually contains quite a bit of moisture, this will generally immediately saturate the oil with water and produce a meaningless analysis.) The oil temperature is recorded at the time the sample is taken and the sample is then sent to a chemical laboratory to analyze the ppm water in oil.

From the ppm in the oil sample and the temperature of the oil, the Piper chart can be used to get an approximate indication of the percent moisture in the kraft paper.

Note that the temperature of the oil/paper interface has a significant effect on the equilibrium moisture concentration, but the temperatures of the oil and the paper vary depending on location. We would then expect the equilibrium moisture concentration to vary as well, which it does.

Generally, the insulation near the hottest spot will have less percent moisture than insulation exposed to cooler oil at the bottom of the transformer. An ‘‘average’’ value of the percent moisture concentration could be calculated from an ‘‘average’’ temperature; however, this may result in a misleading assessment of the transformer’s state because of the wide variation in moisture concentrations.

A conservative assessment would base the percent moisture on the oil temperature at the bottom of the tank. According to the Transformer Maintenance Institute, 2% is the absolute upper limit for acceptability for percent moisture in kraft paper.

Generally, if the percent moisture is less than 1%, the transformer is considered ‘‘dry.’’ There is also an equilibrium equation between vapor pressure of water in air (humidity) and % water in paper.

T = 40.17 + 22.285 Ln pct + 14.056 Ln vap (8.8.2)
where vap vapor pressure, mmHg.

Since the dew point of air is related to the vapor pressure, a dew-point measurement of the space inside a transformer before oil filling is a very good indication of the amount of water locked in the paper. This will determine whether oil filling should proceed or further drying is necessary.

PARAMETERS THAT AFFECT THE DEGRADATION OF TRANSFORMER OIL BASIC AND TUTORIALS

PARAMETERS THAT AFFECT THE DEGRADATION OF TRANSFORMER OIL BASIC INFORMATION

What Are The Parameters That Affect The Transformer Oil?

Heat

Just as temperature influences the rate of degradation of the solid insulation, so does it affect the rate of oil degradation. Although the rates of both processes are different, both are influenced by temperature in the same way. As the temperature rises, the rates of degradation reactions increase. For every 10° (Celsius) rise in temperature, reaction rates double!

Oxygen

Hydrocarbon-based insulating oil, like all products of nature, is subject to the ongoing, relentless process of oxidation. Oxidation is often referred to as aging.

The abundance of oxygen in the atmosphere provides the reactant for this most common degradation reaction. The ultimate products of oxidation of hydrocarbon materials are carbon dioxide and water.

However, the process of oxidation can involve the production of other compounds that are formed by intermediate reactions, such as alcohols, aldehydes, ketones, peroxides, and acids.

Partial Discharge and Thermal Faulting

Of all the oil degradation processes, hydrogen gas requires the lowest amount of energy to be produced. Hydrogen gas results from the breaking of carbon–hydrogen bonds in the oil molecules.

All of the three fault processes (partial discharge, thermal faulting, and arcing) will produce hydrogen, but it is only with partial discharge or corona that hydrogen will be the only gas produced in significant quantity.

In the presence of thermal faults, along with hydrogen will be the production of methane together with ethane and ethylene. The ratio of ethylene to ethane increases as the temperature of the fault increases.

Arcing

With arcing, acetylene is produced along with the other fault gases. Acetylene is characteristic of arcing.

Because arcing can generally lead to failure over a much shorter time interval than faults of other types, even trace levels of acetylene (a few parts per million) must be taken seriously as a cause for concern.

Acid

High levels of acid (generally acid levels greater than 0.6 mg KOH/g of oil) cause sludge formation in the oil. Sludge is a solid product of complex chemical composition that can deposit throughout the transformer. The deposition of sludge can seriously and adversely affect heat dissipation and ultimately

result in equipment failure.

TRANSFORMER OIL CONTAINMENT BASICS AND TUTORIALS

TRANSFORMER OIL CONTAINMENT BASIC INFORMATION
How To Contain Transformer Oils?


Oil containment
Even where the more traditional system of chippings and sump is used as a base for the transformer compound, consideration will need to be given to the possibility of loss of all the oil from the transformer tank and its cooler. Suitable provision must be made to ensure that this will not enter drains or water courses.

Such provision will normally be by means of a bund wall surrounding the transformer and its cooler which together with any sump must be capable of containing the total oil quantity in addition to the maximum likely rainfall over the area.

Since the bunded area will under normal operating conditions need provision for storm water drainage, then suitable oil interception arrangements must be made for separation and holding any oil released.

Segregation and separation

Where it is not economic to consider the type of elaborate measures described above, then other design features must be incorporated to allow for the possibility of fire. Such features involve segregation or separation of equipment.

Separation involves locating the transformer at a safe distance from its standby, where one is provided, or any other plant and equipment which must be protected from the fire hazard. A distance of 10 metres is usually considered to be sufficient.

This means that not only must the transformer be a minimum of 10 metres from its standby, but all connections and auxiliary cabling and services must be separated by at least this distance.

On most sites such an arrangement will be considered too demanding of space, so this leads alternatively to the use of a system of segregation, which relies on the use of fire-resistant barriers between duty and standby plant and all their associated auxiliaries.

The integrity of the barrier must be maintained regardless of how severe the fire on one transformer or of how long the fire persists. In addition the barrier must not be breached by an explosion in one of the transformers, so it will normally be necessary to construct it from reinforced concrete and of such an extent that flying debris from one transformer cannot impinge on any equipment, including bushings, cables, cooler and cooler pipework or switchgear associated with its standby.

Generally for access reasons transformers should be at least 1 metre from any wall but this space may need to be increased to allow for cooling air.

TRANSFORMER MINERAL INSULATING OIL HEALTH AND ENVIRONMENTAL CARE BASICS AND TUTORIALS

TRANSFORMER MINERAL INSULATING OIL HEALTH AND ENVIRONMENTAL CARE BASIC INFORMATION

What Is The Health and Environmental Care Procedure For Transformer Oils?

Health issues

Users should obtain a Material Safety Data Sheet (MSDS) for each dielectric fluid in use. Where instructions differ from recommendations made here, the instructions of the manufacturer are to be followed.

Although there is no special risk involved in the normal handling of insulating fluids addressed in this guide, attention should be focused to the general need for personal hygiene or the practice of washing skin and clothing that may have come in contact with insulating oil. Personnel should avoid contact of the fluid with their eyes.

When dielectric liquids have to be disposed of, certain precautions are necessary to comply with local, state, and federal requirements in the United States. These oils are generally classified as special, regulated or hazardous waste depending upon the individual state.

The following procedures are not intended to supersede local, state, or federal regulations. Unless a PCB analysis has been performed, it is prudent to assume that the batch of oil contains PCBs and to act accordingly. The absence of PCBs in a volume of oil in or from a piece of equipment can be established only by analysis of that oil.

Leaks and spills

During equipment inspection or servicing, routine checks should be made of the equipment and surroundings for leaks. Areas to check and repair should include valves, bushings, gauges, tap changers, welds, sample ports, manhole covers, pipe fittings, pressure relief valves, etc. The user is referred to IEEE Std 980-1994.

New transformer oil as received from a refiner is very unlikely to contain PCBs. However, many older transformers and other pieces of electrical equipment in service are filled with mineral insulating oil that contains PCBs.

Since 1977, various federal, state, and local environmental regulations have governed the handling and processing of mineral oils containing PCBs. While these regulations can add substantially to the complexity of spill cleanup and disposal of oils, they should not be disregarded.

Minor spills

Minor spills, such as those occurring in the manufacture or repair of equipment, can be cleaned using absorbent rags or other materials.

Spills on soil

Soil acts as an absorbent and should not be allowed to become saturated with mineral insulating oil. Users should consult the applicable local, state, and federal guidelines in the United States for spills of mineral oil onto soil and the remedies available. Depending on state and local regulations, spills to soil may have to be reported to one or more regulatory agencies.

Spills on water

Because mineral insulating oils float on water, a spill can be contained by using floating booms or dikes. Section 311 of the Federal Water Pollution Control Act as amended, 33 U.S.C. 1251 et seq, also known as the Clean Water Act as found in Title 40 Code of Federal Regulations Part 110, imposes reporting requirements for petroleum oils that are spilled into navigable water ways.

The requirement to report is triggered by the appearance of a sheen on the surface of the water. If a sheen is noted, the U. S. Coast Guard must be notified, as well as the National Response Center.

Once the mineral oil has been concentrated, it can be removed from the surface of the water by systems that are normally used for petroleum spills. These include pumps, skimmers, physical absorbents, and fibers that are fabricated into floating ropes.

NOTE—If spilled mineral insulating oils are known or assumed to contain any concentration of PCBs, they must be treated as a PCB containing liquid. Also refer to the Spill Policy Guide of the Environmental Protection Agency (see PCBs 761.120, Title 40 Code of Federal Regulations Part 761).

TRANSFORMER OILS TESTING OF NEW OIL PROPERTIES BASICS AND TUTORIALS

TRANSFORMER OILS TESTING OF NEW OIL PROPERTIES BASIC INFORMATION

Testing Of Transformer Oil As Recommended In IEEE Std C57.106-2002

When mineral insulating oil specified to conform to ASTM D3487-00 is received, it should be tested to verify conformance with ASTM D3487-00. Testing of the oil for full conformance of all property requirements of ASTM D3487-00 is only justified under circumstances determined by the purchaser.

As a minimum, it is recommended that the purchaser require the supplier to provide a certified set of tests for the oil that demonstrate that the oil, as shipped, met or exceeded the property requirements of ASTM D3487-00.

For those circumstances where a full set of tests according to ASTM D3487-00 are not justified, it is recommended that, at a minimum, the tests shown in Table 1 of this guide be considered. The purchaser of the oil should conduct tests sufficient to satisfy concerns regarding conditions of shipment that might result in non conformance to ASTM D3487-00 property requirements.  

Table 1 lists several of the more important tests with values that should help in the decision regarding acceptance of the new mineral insulating oil.

Insulating oil is ordinarily shipped in three types of containers: drums or totes, tank trailers, and rail cars. Rail cars are usually under the control of the supplier and dedicated to insulating oil shipment, so they tend to be the cleanest.

Highway trailers are used to transport many different chemical products as well as insulating oil; these trailers are therefore subject to chemical contamination. Special cleaning and drying procedures may be necessary.

If problems are encountered, check the history of the shipping containers to see that they have been cared for properly. It is recommended that the purchaser require the delivery of oil in containers that are properly cleaned to guarantee delivery of oil conforming to ASTM D3487-00.

Drums and totes are the least desirable method of insulating oil transport but may be necessary for small purchases. Drums and totes should be stored under cover to prevent contamination by moisture.

Before processing, it is necessary to check the quality of the oil in each drum or tote or after blending the oil in a large tank. Each tank load or each shipping unit of oil as received at the customer’s site should undergo a check test to determine that the electrical characteristics have not been impaired during transit or storage.

Table 1 contains a list of recommended acceptance tests for shipments of mineral insulating oil as received from the supplier. Some users may not wish to perform all these tests; however, as a minimum, dielectric strength and dissipation factor (power factor) as listed in Table 1 should be performed.

It is satisfactory to accept oils that exhibit characteristics other than those described by the values in Table 1, providing that the users and the suppliers are in agreement.