Electrical oils have a different set of analyses compared to lubricating oils. Additionally, electrical oils have two diagnoses as both the fluid and the dissolved gases are analysed to give a complete overview of the transformer condition.
The tests performed on these samples are typically performed every 6 months to 1 year depending on voltage (see “when to sample”). If a cautionary fault is identified then the sampling interval should be halved (i.e. twice as often), and if a serious fault is identified immediate resampling should be performed to confirm.
The fluid has three main functions (1) to separate the electrical contacts acting as an electrical insulator, (2) dissipate heat within the transformer and (3) to provide arc quenching for switchgear operation.
This section assumes the reader has a basic knowledge of the electrical function and significance of transformer, switch-gear and tap-changer system. It also assumes the reader is familiar with terms such as arcing and sparking. If so you can skip the grey box below and move onto the next page. However, if you do not have an electrical background and are not familiar with these terms please read the grey box below before proceeding.
Not an electrical engineer? A simple overview of some of the terms used
- Transformer (oil insulated) is simply two copper coils (windings), with the windings usually having different number of turns, wrapped in a specialist paper and submerged in an electrical insulating fluid to allow a step up or down in voltage via electromagnetic induction.
- Switchgear is used for important safety requirements; e.g. isolation and circuit protection (overload and short circuit). Oil emerged switchgears composes of electrical disconnect switches, fuses and circuit breakers either individually or in combinations to isolate and protect electrical equipment.
- Tap Changer is a system to allow voltage regulation by a connection point selecting variable number of turns.
- Spark is when the insulating fluid or air breaks down to allow electrons to jump the gap between the conductors, temporarily discharging the charge that led to the potential. Most people will be familiar with a static spark when touching a surface that has built a static charge or for example a petrol/gas engine spark plug.
- Arcing is similar to a spark, but is where the fluid or air between the conductors remains ionized meaning that electrons can continue to jump the gap even at voltages lower than the original breakdown voltage.
- Floating Potential – Most people are familiar with a circuit being grounded or earthed for safety. In contrast, a floating potential is where the circuit is not earthed/grounded, which presents a safety concern within the system.
Please note these terms are referencing solely their use in relation to electrical oil / DGA analysis and some of these terms have additional / more detailed definitions and uses for physicists describing electrical circuits.
Routine Electrical oil diagnosis limits
The following table summarises some of the routine electrical oil limits used typically by an electrical oil laboratory.
These are LearnOilAnalysis general guidelines. Note Trending may be used by the lab to over-rule these general limits. Additional electrical oil diagnosis information sources are available from: BS EN60422:2013.
Dielectric breakdown – of the two main functions of the insulating fluid, one of them is to provide an electrical insulation. The dielectric breakdown is the voltage at which the insulator no longer prevents an electrical discharge across (arrowed red to right) two electrical contacts submerged into the fluid. The method involves submerging the two electrical contacts in the fluid and gradually increasing the voltage until the insulating properties are over-come termed the breakdown voltage. The test is repeated several times and an average breakdown voltage is obtained.
Diagnostic significance: Presence of contamination such as long fibres, water, dirt and oxidation products can all contribute a low dielectric breakdown. The breakdown voltage is an excellent overall indicator of contamination in the fluid as the contaminants will have conducting properties.
Moisture – This is a measure of the water in the sample. The maximum allowable content of water/moisture in electrical oil is much less than a lubricated system. This is owing to the significance of water in hindering the ability of the insulating oil to perform its function in being an electrical insulator. Owing to the difference in solubility of water in the insulating fluid at very low concentrations temperature becomes far more significant to determine the water content. This is often referred to as a temperature adjusted water. Temperature adjusted water takes into consideration the temperature of the water measured in the laboratory as well as the temperature of the oil at time of sampling provided by the sampler to adjust the laboratory measured water to the water measured in a transformer.
Diagnostic significance: Presence of water contamination can contribute to increased oxidation and contribute to a low dielectric breakdown. Water can enter the transformer via atmospheric air through a breather, or through degradation of the cellulose paper insulation. Water can also contribute to paper insulation breakdown as the water breaks down the paper insulation.
Acidity – Excessive temperature and the presence of oxygen in air causes the oil to oxidise forming organic acids. This is accelerated in the presence of metallic catalysts such as the metallic windings. Acidity is measured by titration with an alkali using a coloured indicator to identify the concentration of alkali needed to neutralise the acid changing the indicator from orange to green as identified to the left.
Diagnostic significance: Acidity build up can lead to varnish formation and catalyse the breakdown of cellulose within the paper insulation. Acid products can increase the solubility of the moisture in the oil.
Particle count – Details of the ISO particle count are covered in “Tests on LearnOilAnalysis report – particle count”. Particles can accumulate in the system from wear metals and corrosion metals from oil pump bearings where fitted. However, particles matter can also be in the form of carbon. Carbon particles form at temperatures >500OC and can be caused by localised overheating in on-load tap changer diverter switches that end up entering the bulk oil tank contaminating the oil-immersed parts of the transformer.
Dissolved Gas Analysis
Dissolved gas analysis is the study of fault gases in transformer oil to predict transformer faults. This is different to the fluid condition analysis as it specifically identifies the condition of the electrical system and the faults within it. DGA analysis can predict fault gases up to 4 years in advance of a failure meaning significant plans can be made to take corrective action on the system.
DGA Fault gases structure with relative bond energies in average bond dissociation enthalpies in kcal per mole in blue. The more serious fault gases have larger structures / more double bonds. The order of severity of fault gases is Hydrogen < methane < ethane < ethylene < acetylene, i.e. hydrogen is the least serious and acetylene is the most serious.
In tap changers the concentrations of gases are usually much higher owing to the nature of the repeated changing contacts causing high temperature sparking. However, in tap changers the fault gas for carbon monoxide is usually lower owing to less/no paper insulation present.
|Learn Oil Analysis Typical Fault Gas alarm limits|
|Test Name||Example Fault type||Temperature Range||Transformers||Switchgears||TapChanger|
|Hydrogen (ppm)||Arcing corona / start-up||
(100 OC to 300OC)
(100 OC to 300OC)
|Ethane (ppm)||Local overheating||
(300 OC to 700 OC)
|Ethylene (ppm)||Severe overheating||
|Carbon Monoxide (ppm)||Paper insulation / severe overloading||n/a||500||500||100|
Note Trending may be used by the lab to over-rule these general limits.
Ratios Methods (80ml) – Although, the method of determining faults by DGA includes alarm limits in fault detection, it is the ratio of the gases to one another that determines the fault diagnosis. There are many different methods each with their own merits for use in electrical oil diagnosis. Examples of which include:
- Rogers Ratios
- Duval’s Triangle
- IEC Ratios
- IEEE Conditions
- Key Gases
All of these methods above are used by the LearnOilAnalysis laboratory in electrical fault diagnosis, but our default diagnostic method is the Rogers ratios method followed by Duval’s triangle where confirmation is needed.
Specialist electrical oil testing.
Elemental Analysis– This is useful in identifying dissolved wear metals in the oils. Unlike lubricating oils there are very little or no detectable elements in the sample other than sulphur (or silicon in silicone based fluids) from the base oil in new oil.
Diagnostic significance: The most common metals dissolved in the oil are iron with either copper or aluminium depending on the alloy used in the coils. However, there are many metals that may appear in the sample. Some example sources are below.
|Typical Metals found in electrical oils|
|Test Name||Example source|
|Iron (ppm)||Alloys used in coil construction (usually with copper or Aluminium), or Debris from sampling valve when not flushed correctly.|
|Copper (ppm)||Alloys used in coil construction, bearing pump shaft / impeller wear in pumps (where fitted to cool transformer) or Debris from sampling valve when not flushed correctly. Copper from corrosive sulphur presence.|
|Aluminium (ppm)||Alloys used in coil construction and bearing pump shaft / impeller wear in pumps (where fitted to cool transformer).|
|Lead (ppm)||Brazes, Solders, lead based paint and bearing pump shaft / impeller wear in pumps (where fitted to cool transformer).|
|Zinc (ppm)||Plating, brazes, solders, bearing pump shaft / impeller wear in pumps (where fitted to cool transformer) or Debris from sampling valve when not flushed correctly.|
|Silicon (ppm)||Silicone fluids, Silicone grease, caulking sealant, Environmental Dirt (with Aluminium), damaged / overheated gaskets|
|Silver (ppm)||Bearing pump shaft / impeller wear in pumps (where fitted to cool transformer)|
|Tin (ppm)||Bearing pump shaft / impeller wear in pumps (where fitted to cool transformer), or Debris from sampling valve when not flushed correctly.|
Corrosive Sulphur (60ml), DBDS (100ml) and Passivators (100ml) – Sulphur containing compounds (organo-sulphur compounds) exist in mineral oil based products as it is part of crude oil. Generally, as the oil is treated to make the different base stocks the reactive sulphur compounds are removed. However, poor refining or contamination can lead to reactive sulphur compounds that at high temperatures (e.g. at switching equipment) can attack copper electrical contacts. The corrosion can include the formation of copper-sulphur compounds e.g. copper (I) sulphide (Cu2S) – known to mineralogists as Chalcocite (from the Greek khalkos meaning copper). This Cu2S deposition into the paper insulation can lead to a drastic drop in insulating properties of the paper and lead to overall equipment failure. Presence of Dibenzyl disulphide (DBDS), commonly used as an anti-oxidant in rubbers, stabilisers and as a silicone oil additive can also lead to Cu2S deposition at relatively normal operating temperatures. Metal passivators such as tolyltriazole derivatives (~100ppm) are used to inhibit the chemical reactions between copper and sulphur within the insulating fluid.
Diagnostic significance: This is particularly important to monitor where the equipment is paper insulated, at equipment running at high temperatures with low oxygen (e.g. where gas blankets are used) or where unvarnished / coated copper is used within the system. Additionally any measurement of low passivator content within the oil should automatically schedule a corrosive sulphur measurement.
Density– This is useful for type of fluid determination (mineral vs synthetic fluids). It tends to be used in cold climate situations where water freezing within the transformer can lead to sufficient density reduction that it floats on top of the fluid rather than the other way round. This can cause problems with electrical circuits when it melts.
Dielectric Dissipation Factor – DDF – (aka TAN Delta) (65ml), Power Factor (PF) (65ml) and Resistivity (65ml) – DDF is a measure of how dielectric strength is dissipated as heat. Another measurement is Power factor, which is the same test as DDF, except the measurement phase angle is different when calculating the value. With both DDF and PF, a low value means very little is lost as heat, but a high value suggests it is being lost as heat, typically owing to contamination. Resistivity measures the resistance of the fluid to conduct. Oil is naturally a poor conductor and it is the contamination within the fluid that increases conductivity and hence reduces resistivity. It is different to dielectric breakdown that rather than measuring the uncontrolled breakdown of the insulation leading to an arc or spark, it allows monitoring of the resistance drop and current flow caused by contaminants in the fluid.
Diagnostic significance: With contamination increase resistivity and dielectric breakdown would both be expected to decrease, whilst DDF and PF increase.
Flash point (120ml)– This is usually used where safety regulations require this test on the fluid. The predominant cause of a low flash point is contamination with solvent, but also in very serious accumulation of fault gases from extensive sparking discharges. Hence, this naturally compliments DGA (see above) analysis that detects and identifies these fault gases.
Furans (FFA) and Est. Degree of Polymerisation (DP) – Furans, or Furfuraldehyde (FFA) occur upon thermal degradation of paper insulation. It is an excellent indicator of the condition of the paper insulation within the transformer. A high result suggests the paper insulation is in a poor condition. The paper insulation is made of cellulose, which is a long chain of glucose (sugar) molecules that forms the structure we are familiar with as paper. Estimated Degree of Polymerisation (DP) provides an estimate of the average chain length (i.e. how many glucose molecules make up a cellulose chain). New paper will typically have a value between 1000 and 1500, but as it dries this will reduce to between 900 and 1200 in the new transformer. If the paper is intact then the DP will remain steady near the new transformer value. However, as the paper insulation degrades the chains will break and the average chain length (est. DP) will decrease leading to a reduction in DP. A low DP suggests the paper insulation is in poor condition.
Diagnostic significance: FFA can be broken down into its constituents to identify the failure type.
|Symbol||Full Name||Failure Type|
|2FAL||2-Furaldehyde||Overheating / old faults (lasts a long time). Used for Est. DP.|
|2ACF||2-acetylfurn||Rare – lightning Strikes.|
|5M2F||5-methyl-2-furaldehyde||Local Severe overheating|
Levels of 5H2F can increase in the presence of high oxygen – e.g. if system is free breathing and does not have a gaseous blanket. This is only traditionally observed on Kraft rather than thermally upgraded paper in the system.
The oil to paper ratio – typically 20:1 should be taken into consideration when accessing the severity of the furans present with the value becoming more significant the higher the ratio becomes.
InterFacial Tension (IFT) – This can be oil-water or oil-air. Most commonly used for electrical oils is the oil-water IFT. A high interfacial tension suggests the oil and water separation is being maintained at the interfacial surface. This is because the oil is non-polar whilst the water is polar meaning the surfaces are separated.
Diagnostic significance: When the oil becomes oxidised or sludges the oxidised products (which are polar) lead to a reduction in the IFT. Equally incompatibility of two fluids, or contamination (e.g. water/dirt etc) added to the electrical oil system will also lead to a reduction in IFT. Overall it is an excellent tool in confirming overall deterioration of the fluid. A high IFT helps maintaining oil seals, so IFT should also be added to a suite if there is excessive or sudden leakage from the system.
OQIN (Oil Quality Index) / Myers Numberv – This uses the interfacial tension divided by the acidity or acid number data to determine the overall oil condition.
|271-600||Proposition A oils|
|22-4||Very Bad Oils|
|9-21||Extremely Bad Oils|
Polychlorinated biphenyls (PCBs) (20ml) – PCBs were discovered in the mid 1800s as a by-product of coal tar, which a few decades later was successful synthesised in a laboratory. The non-flammable properties were used widely in the 1920s and 1930s. Over the following decades papers were published identifying PCBs as a toxin (owing to its high chlorine content) and in the 1970s it began to be officially recognised as such with its use being limited entirely to ‘closed’ systems such as transformers. Its use began to be restricted and eventually banned in the 1980s onwards, but each country has its own regulations for handling, transport and disposal.
Diagnostic significance: Limits used for regulations and transport as they are based on government regulations are subject to change, but typical maximum limits are 50ppm (caution) and 500ppm (serious). It is advisable to confirm the regulations in your local authority for disposal of PCBS.
This is predominantly important for when changing transformer oils and hence wishing to dispose of the old oil. However any electrical system built prior to 2000 should be monitored regularly owing to the likelihood of PCB content / contamination.
For more information see your local government environmental / safety regulations e.g. http://www.hse.gov.uk or http://www.doeni.gov.uk/niea/ann_reg_ofpcbholders_guidance_web.pdf
Pour Point – This is predominantly used where the electrical oil is likely to be in very cold climates. It is commonly combined with a viscosity test as they help provide information on the oils ability to flow.
Viscosity – This is a test performed as standard on lubricating oils, but tends to be a none-standard test on electrical oils. This is because the viscosity dictates how easily the fluid will flow through convection fins, as part of the transformer cooling system in the transformer to dissipate heat. Only under extreme conditions of excessive oxidation would a change (increase) in viscosity be significant.