Transformer Oil Testing Methods Value.
Transformer Oil Testing is a proven loss prevention technique which should be a part of any condition based predictive maintenance program. This early warning system can allow maintenance management to identify maintenance priorities, plan work assignment schedules, arrange for outside service, and order necessary parts and materials. GlobeCore uses test results to diagnose transformer problems.
The transformer’s fluid not only serves as a heat transfer medium, it also is part of the transformer’s insulation system. It is therefore prudent to periodically perform tests on the oil to determine whether it is capable of fulfilling its role as an insulant. Some of the most common tests for transformer oil are: Dissolved Gas In Oil Analysis, screen tests, water content, metals-in-oil, and polychlorinated biphenyl
(PCB) content. In this article, we will examine the value and benefits of each test.
|transformer oil testing methods||ASTM Method||Significance of Transformer Oil Testing Method||Units|
|Color||D1500||Used to observe darkening of the oil by comparing it to previous samples of oil from the same transformer. Transformer oil colour is determined by means of transmitted light and given a numerical value (0-5) based on comparison with a series of color standards. Noticeable darkening oil indicates either contamination or that arcing is taking place.||0-5|
|Dielectric breakdown voltage||D877||Measures the voltage at which the oil fails electrically, which is indicative of the amount of contaminant (usually moisture) in the oil. The dielectric breakdown voltage is measured by applying a voltage between two electrodes under the oil. New oil should have a minimum dielectric strength of 35 kV by ASTM Transformer Oil Testing Methods.||kV|
|Dissolved gas analysis (DGA)||D3612||Identifies various gas ppm levels that are present in transformer insulating oil. Different gasses will dissolve in the oil that indicate various types of thermal and electrical stress occurring within the transformer. An oil sample tube and syringe is used to draw, retain and transport the oil sample in the same condition as it is inside a transformer with all fault gases dissolved in it.||ppm|
|Dissolved metals||D7151||Identifies any dissolved metals that could originate from overheating or arcing and a portion of the particulate metals that may originate from mechanical wear. Measured by inductively coupled plasma atmonic emission spectrometry (ICP-AES) and expressed in micrometers.||µm|
|Flash point, fire point||D92||Indicates the volatility of insulating oil by measuring the minimum temperature at which the heated oil gives of sufficient vapor to form a flammable mixture with air.||°C|
|Interfacial tension||D971||Measures the presence of soluble contaminants and oxidation products in transformer oil. Expressed in mN/m, it is a test of interfacial tension of water against oil, which is different from surface tension in that the surface of the water is in contact with oil instead of air. A decreasing value indicates an increase in contaminants and/or oxidation products within the oil.||mN/m|
|Furanic compounds||D5837||Determines the presence of degradation in cellulosic materials such as paper, pressboard, and cotton, which generate furanic compounds in the insulating oil. Measurements are made using high-performance liquid chromatography (HPLC).||ppb|
|Moisture (Water) Content||D1533||Measured in parts per million (ppm) using the weight of moisture divided by the weight of oil. Moisture content in oil lowers the insulating system dielectric strength and allows flashover that can damage a transformer. For mineral oil, a generally accepted maximum moisture content is 35 ppm. This test does not measure the water content in the transformer paper insulation.||ppm|
|Neutralization (Acid) number||D974||New transformer oils contain practically no acids. The acidity test measures the content of acids formed by oxidation and contaminates. Measurements are made by the amount of potassium hydroxide (KOH in mg) required to neutralize the acid in one gram of oil. Typically, results of 0.10 mg KOH/gram of oil or less are considered good. Higher values are indicative of a problem.||mg KOH/g|
|Oxidation inhibitor content||D2668||Measures the amount of 2,6-ditertiary-butyl paracresol and 2,6-ditertiary-butyl phenol that has been added to new insulating oil as protection against oxidation. In a used oil it measures the amount remaining after oxidation has reduced its concentration.||%|
|Polychlorinated biphenyls (PCB) content||D4059||Detects the concentration level of polychlorinated biphenyls in transformer oil by gas chromatography. Measured in ppm, it also applies to the determination of PCB present in mixtures known as askarels.||ppm|
|Pour point||D97||Indicates the lowest temperature at which the insulating oil will flow. This test is particularly useful in cold climates to ensure that the oil will circulate and serve its purpose as an insulating and cooling medium.||°C|
|Power Factor||D924||Indicates the dielectric losses of the oil, or energy that is dissipated as heat. Useful for measuring changes within the insulating oil resulting from contamination or deterioration. The power factor of insulating oil equals the cosine of the phase angle between an ac voltage applied and the resulting current. For mineral oil, the power factor of new oil should not exceed 0.05 percent at 25 degrees C.||%|
|Relative density (specific gravity)||D1298||Determines the density, relative density (specific gravity), or API gravity of transformer oil by use of hydrometer at a reference temperature. A high specific gravity indicates the oil’s ability to suspend water. In extremely cold climates, specific gravity can be used to determine whether ice will float on the oil.||number|
|Resistivity||D1169||Measures the electrical insulating properties of transformer oil under conditions comparable to those of the test. A low resistivity reflects a high content of free ions and ion-forming particles in the insulating oil, and normally indicates a high concentration of conductive contaminates.||ohms|
|Visual examination||D1524||Oil is visually examined by passing a beam of light through it to determine transparency and identify foreign matters. Contamination of the oil is exhibited by poor transparency, cloudiness, or the observation of foreign particles.||Bright, dark, clear of particles etc.|
See bigger list of transformer oil testing methods in the end of the article.
The performance characteristics of transformer insulating oil are monitored and tested at several stages during its service life. Regular monitoring of the oil’s quality and condition is a part of the process of servicing electric power equipment. The condition of the oil, its purity and contamination level will greatly help in indicating the condition of the transformer’s solid insulation. It is therefore, essential to the life of the transformer to periodically monitor the condition of the insulating oil. The heart of the transformer is the solid insulation, but the insulating oil is the life blood of the transformer. Without the life blood, the heart will die.
The ability of insulating oil to maintain its original performance characteristics during long term operation of electric equipment is referred to as “oil stability.” If the electric power equipment has no defects and operates in accordance with design and expectations, the performance characteristics of new oil will change and degrade slower. When new, transformer oil has a very light color and complies with performance standards that include dielectric strength and other important characteristics. During the course of the oil’s service life, the stability of the oil decreases and visible changes occur and oil’s color slowly becomes darker and darker.
Contaminated oil usually has a high ash content, increased acidity and presence of low molecular acids. Acidic sludge forms in contaminated oil and aggressively attacks the cellulose insulation and reacts with the metals of the transformer’s other internal components.
Timely oil monitoring and oil analysis programs can identify when the oil needs to be changed or serviced through an oil purification and/or oil regeneration process. Servicing the oil before it becomes aggressive against the solid insulation is the key to extending the service life of your transformers.
The main physical and chemical properties tested in Transformer Oil Testing Methods are the oil’s dielectric strength, dissipation factor, flashpoint, color, amount of solid particulate matter, water content, gas content and the oil’s acid number.
Dielectric strength is one of the most important indications of oil stability and this is often the first test performed. The “dielectric breakdown test” is calculated as an average of five breakthroughs achieved in a standard discharger with two electrodes submersed in the oil at 2.5 mm distance from each other. Six breakthroughs are achieved in the test and the last five are averaged. If the oil is fresh, the lowest allowable breakthrough voltage is 30 kV. In some transformers, that meets the minimum operating standard.
Decreasing dielectric strength is caused by contamination of the oil by gas, moisture, cellulose fibers or other particulate matter.
A similar process is used to calculate the oil’s “dissipation factor.” It is the the oil’s ability to neutralize energy, prevent breakthroughs and cool the transformer. It is a characteristic of the oil’s quality and purity and acidity. In general, an increased dissipation factor means degradation of the oil’s dielectric capabilities.
See more video about transformer oil purification
The color of transformer oil changes from light yellow to cloudy brown under the influence of temperature, contaminants and electric current. The color is not in itself an indication of any specific problem, but a dark color is usually an indication of aged and/or contaminated oil.
Transformer Oil Testing Methods
- Color; e.g., ASTM D1500
- Dielectric breakdown voltage; e.g., D 877, ASTM D1816
- Dissolved gas analysis; e.g., ASTM D3612
- Dissolved metals; e.g., ASTM D7151
- Flash point, fire point; e.g., ASTM D92
- Interfacial tension; e.g. D 971
- Furanic compounds; e.g., ASTM D5837
- Karl Fischer moisture; e.g., ASTM D1533
- Liquid power factor; e.g., ASTM D924
- Neutralization number; e.g., ASTM D974
- Oxidation inhibitor content; e.g., ASTM D2668
- Polychlorinated biphenyls content; e.g., ASTM D4059
- Relative density (specific gravity); e.g., D 1298, ASTM D1524
- Resistivity; e.g., ASTM D1169
- Visual examination; e.g., ASTM D1524
The presence of solid particles in the oil and the acid number of the oil are two related oil purity characteristics. Unsolved materials accumulated in the oil in the form of sludge or suspended particles (fibers, dust, solved paint, metal particles, ash etc) degrade the oil’s dielectric properties and promote oil oxidation. The more particles that are present in the oil, the faster the oil ages. The acid number is expressed as milligrams of KOH required to neutralize all acids in a gram of oil and indicates the degree of oil aging. A normal and acceptable acid number is 0.25 mg KOH/g, while the limit of contaminant content is 515 parts per million (ppm).
Moisture and gas content in transformer oil must be tested for thoroughly. Water and gases are very damaging to your transformer insulation system and are two main cause of the oxidation process and oil aging process.
Moisture and water content is measured as amount of hydrogen when reacting the oil with calcium hydride in a certain period of time. Gas content is measured by an absorptiometric analyzer or a chromatographer.
The oil’s flashpoint and the oil’s setting point are two indications of the general fire safety of the oil and the oil’s ability to operate in adverse temperature conditions both hot and cold.
The are distinct advantages of testing and analyzing transformer oil before starting your electric power equipment and during scheduled maintenance events. Oil testing allows the operator to determine the equipment’s operating efficiency, conditions and the possibility of future malfunctions. If the purity and quality standards are followed, the equipment will be less likely to experience failures and downtime and unscheduled maintenance and repair costs.
The paper insulation which is normally used to insulate the windings of a transformer is a cellulose product. If a transformer becomes overloaded for any reason, the windings will generate more heat and deteriorate the cellulose insulation. So, insulation overheating measurement is also transformer oil testing methods. A DGA test can identify an overloaded transformer by a test result showing high carbon monoxide, high carbon dioxide, and in extreme cases, even elevated methane and ethylene.
If a transformer is overloaded for a long period of time, the deteriorating condition of the cellulose will shorten the life of the transformer. When the cellulose insulation breaks down to the point where arcing starts to occur, the transformer must be taken out of service.
Insulation Liquid Overheating
Overheating of the liquid insulation is a slightly different problem in transformers and can be on of transformer oil testing methods. A DGA test will indicate high thermal gases (methane, ethane and ethylene) as a result of overheating of the liquid.
These gases are formed from a breakdown of the liquid caused by heat. Heating may be caused by poor contacts on a tap changer, or loose connections on a bushing or a grounding strap, or circulating currents in the core due to an unintended core ground.
Actions that can be taken once a thermal gas problem is detected would depend on the severity of the problem. If conditions are not severe, the transformer should be monitored closely. If conditions gets worse, and thermal combustibles elevate, the transformer will need to be taken out of service. If the combustibles are stable and remain present, the transformer should be inspected at the next outage or downtime scheduled.
Corona is considered to be partial discharge and occurs at areas of high electrical stress, such as at sharp points along an electrical path. Partial discharge is commonly explained as being intermittent
Arcing is the most severe condition in a transformer because it indicates a breakdown of the insulation.
The presence of acetylene is an indicator of arcing and so it’s one of the most important transformer oil testing methods; and even low levels of this gas should cause concern.
Normally, arcing occurs only after other problems surface which show up through DGA testing.
However, the high energy required to produce an arc will cause all combustibles to be elevated. If the arc occurs in the area of cellulose insulation, carbon dioxide and carbon monoxide also will be elevated.
Arcing can be generated in many areas of a transformer. Insulation breakdown in the windings, from coil to coil or coil to ground, will result in arcing. A portion of the insulation may deteriorate until it can no longer contain the stress of the electrical conductor. If a winding shorts from turn to turn, or phase to phase, or phase to ground, arcing will occur and the transformer will fail. When arcing occurs in the area of the windings, the usual result is de-tanking of the transformer, and a rewind conducted. A loose connection also may cause arcing, but of greater significance would be arcing due to insulation breakdown.
The “screen test” is a collection of physical, electrical and chemical transformer oil testing methods. These tests include dielectric breakdown, power factor, inter-facial tension, acidity, and color. A larger quantity of oil is needed for these tests. To gather the sample, a clean, moisture free container must be used — typically a 1 liter glass bottle. Each test is an indication of how suitable the insulation liquid is for service.
No single test alone will represent or indicate the true condition of the liquid. Therefore, it is suggested that they all be performed.
Transformer Oil Testing Methods are key part of any maintenance program. An annual DGA is the most important test for liquid insulation. Analysis of gases in the oil can indicate insulation overheating/overloading, liquid overheating, partial discharge (corona), or arcing in the transformer. The screen test is a collection of additional physical, electrical and chemical tests, including: dielectric breakdown, power factor, interfacial tension, acidity and color. No single test alone will indicate the true condition of the liquid, so all the screen tests should be performed. Additional useful tests performed by transformer oil laboratories include those for water content, PCBs furanic compounds and metals-in-oil.