OIL SPECIFICATIONS
Mineral oil plays a crucial role in the insulation system of vital transformers on the electric grid. Transformers facilitate energy transfer between electrical circuits without any moving parts, through inductively coupled conductors. The insulation, primarily composed of cellulose, is enhanced by a liquid dielectric. The chosen fluid must serve multiple functions, including preventing flashover, acting as a heat transfer medium, preserving the core and coil assembly, and reducing aging of the insulation by restricting oxygen and moisture ingress. Achieving the right mix of properties involves balancing considerations such as dielectric strength, viscosity, density, volatility, flash point, and chemical stability—all at a reasonable cost and without compromising environmental or safety concerns.
The chosen fluid must serve multiple functions, including preventing flashover, acting as a heat transfer medium, preserving the core and coil assembly, and reducing aging of the insulation by restricting oxygen and moisture ingress.
Specifications
There are several specifications available today that can be used to assure quality of mineral insulating transformer oils. Doble Transformer Purchase Specifications (TOPS) was one of the first specifications in North America, having been first published in 1961 and updated over the years to reflect the changing needs of the industry. Organizations such as IEC, IEEE, and ASTM have similar specifications.
All of these specification standards essentially evaluate the same properties of the oils, differing somewhat in the particular tests included or the methods required; physical, electrical and chemical properties that relate to the functioning of the oil, its composition, purity, and stability. Additional properties, additives and behavior may also be included in these specification documents, for example stray gassing is a mandatory test in TOPS while it is not part of some other specifications. Figure 1 lists some of the properties typically included in oil specifications and the significance in practice of those characteristics.
Figure 1: Relevance of Common Specification Tests
Mineral oils are oxidatively unstable, which can lead to the formation of acidic by-products and eventually sludge deposition in transformer cooler areas. Oxidation inhibitors, such as synthetic additives like DBPC/BHT and DBP, slow down this process by competing for available oxygen. Specifications typically separate oils into classification based on the amount of added antioxidant, as shown in Table 1. In TOPS, oil with passivators which act as metal deactivators is evaluated as inhibited Type II.
Oxidation inhibitors, such as synthetic additives like DBPC/BHT and DBP, slow down this process by competing for available oxygen. Specifications typically separate oils into classification based on the amount of added antioxidant.
Table 1: Inhibitor Classifications
Many commercially available oils have been evaluated against TOPS by Doble Engineering laboratories since the first such report was published in 1953. Reviewing the historical data shows the move away from uninhibited to inhibited oils, shown in Table 2, as refining processes developed and demand for the fully uninhibited oils receded. The oils tested as part of the survey are from refiners globally and include oils from the Americas, Europe and Asia.
Table 2: Inhibited Oils Over the Years
Mineral insulating oils are thermally stable and can withstand temperatures as high as 700°C in low oxygen environments. They are, however, oxidatively unstable, especially at high temperatures. All oxidation stability testing is essentially the same – the oil is aged in an accelerated manner using heat, oxygen, and a copper catalyst. Natural and added inhibitors will slow the aging process and therefore less stringent limits are allowed for uninhibited and less inhibited oils. Maximum concentrations of inhibitors are specified to avoid poor performance of the base oil being masked by the presence of excessive retardants. A typical aging test, ASTM D2440, calls for the heating of the oil at 110°C in the presence of sanded copper wire, which acts as a catalyst, while oxygen is fed to the oil through a thin tube throughout the 64 and 120hour aging periods. At the end of each period, the acidic byproducts and any sludge formed are quantified, as shown in Figure 2.
Mineral insulating oils are thermally stable and can withstand temperatures as high as 700°C in low oxygen environments. They are, however, oxidatively unstable, especially at high temperatures.
Figure 2: Accelerated Aging Testing ASTM D2440
Electrical Properties
To ensure the oil can satisfy the demands of an effective dielectric, several electrical tests are included in TOPS. The dielectric breakdown volage, measured using ASTM D1816, involves a voltage being applied across spherically shaped electrodes with a defined gap of 1mm or 2mm, until a flashover between the electrodes occurs (Figure 3). The limits given in TOPS apply to a fluid that has been filtered and dried, which is generally done with new oil prior to filling in an electrical asset. Typical data for new oil is shown in Table 3.
Table 3: ASTM D1816
Power factor, also referred to as dissipation factor, is a test used to measure the dielectric losses of the fluid at room temperature and at 100°C. Testing at both temperatures helps qualify the type of material causing the losses. A high reading at room temperature not reflected in the higher temperature measurement is an indication of moisture or conducting particles that are driven off in the heating process. A high reading at 100°C suggests the cause is contamination of the new fluid with polar compounds.
The impulse breakdown test is carried out using the cell shown in Figure 4, which is a negative needle to sphere configuration. It is an indicator of the oil’s ability to resist lightning voltage stresses and is influenced by the concentration of polycyclic aromatics. The TOPS limit for this test is 145kV minimum.
Figure 3: Dielectric Breakdown ASTM D1816
Figure 4: Impulse Breakdown Voltage
The gassing tendency (ASTM D2300) is a measure of the ability of an oil to absorb or evolve gas over a set period after the oil has been saturated with hydrogen and has had voltage applied to the oil/gas interface. The resultant ionic bombardment of the oil molecules results in some hydrogen gas being released from saturated hydrocarbon molecules in the oil and some gas absorbed by unsaturated aromatics. The resultant net absorption or evolution under these conditions will determine whether the oil is deemed positive or negative, and the latter can be important under certain high-stress applications.
Physical Properties
Properties such as color and interfacial tension are an indicator of oil purity, with new oils typically having a clear appearance with little color noticeable. Exposure to light can cause darkening due to photodegradation reactions, and contamination or contact with incompatible materials will similarly cause new oils to exceed the 0.5 maximum color allowed. The number refers to a standard color scale that increases in increments of 0.5 as shown in Figure 5.
Figure 5: Color
The interfacial tension (IFT) of an oil is the amount of force needed to break the oil water interface with a fine platinum ring (Figure 6) and is a measure of the polar compounds left in an oil. Clean new oil should easily meet the minimum of 40 mN/m specified by TOPS. Figure 7 plots the data from 2019 survey report and all easily satisfy the requirements. Given the consistently high recent values in IFT which are likely a reflection of more modern refining, an increase in the IFT minimum is under consideration for the next revision of TOPS.
Figure 6: IFT of North American Oils from Survey Report 2019
Pour point, relative density and viscosity are indicators of flow characteristics and the oil’s suitability as a heat dissipation medium. Viscosity is measured at 0°C, 40°C and 100°C to ensure it can perform adequately over the range of temperatures likely to be encountered in service. The pour point is a measure of the oil’s ability to flow at very low temperatures and can be of importance for cold start up conditions. These properties should not change over the service life of the oil and any significant change would indicate contamination or very advanced aging where sludge has precipitated from the oil.
Corrosive Sulfur and Additives
Corrosive sulfur compounds, if present in an oil, will attack copper and silver leaving deposits of metal sulfides on the metal and paper surfaces inside a transformer in service, and can contribute to failure. This has been an ongoing issue in service since the early 2000s and in response, oil specifications, including TOPS, updated the requirements to include more rigorous testing to aid in detecting problematic oils. Corrosive sulfur testing by ASTM D1275 and Doble Covered Copper Deposition (CCD) must both be passed for an oil to be deemed non-corrosive by TOPS. Testing for dibenzyl disulfide and elemental or free sulfur were added as mandatory tests to help reduce the incidence of corrosive sulfur in service. Figure 8 shows copper sulfide deposits on conductor paper insulation from a transformer winding and on the conductor in an in-service bushing.
Figure 7: Copper Sulfide Deposits In Service
Testing by ASTM D1275 involves heating the oil with a small copper strip for 48hours at 150°C and comparing the tarnish level to a standard corrosion chart, as shown in Figure 9. The oil is considered to have failed if the tarnish level is 4a or darker.
The Doble CCD evaluates both the copper strip and a layer of paper aged with it, in both a low and high oxygen environment, to mimic both sealed and free-breathing conservator conditions in the field. Again, the copper is compared to the corrosion chart, and the paper is examined for deposition of copper sulfide, a characteristically shiny deposit on the copper-facing side of the paper wrap (Figure 10). If any one of the paper or metal strips fails, the oil is deemed corrosive.
Figure 8: Covered Copper Deposition Testing
Passivators
Passivators, also known as metal deactivators, are sometimes added to an oil to improve oxidation stability and can also mitigate corrosive sulfur by reducing the rate of metal sulfide reactions. These passivators attach to the metal surfaces thereby reducing the number of reaction sites available for the corrosive sulfur compounds from the oil, as depicted in Figure 11. TOPS specifies there should be no detectable passivator unless agreed otherwise by the buyer.
Figure 9: Passivator Action
Stray Gassing
Dissolved Gas Analysis (DGA) is a crucial test for monitoring electrical asset performance during service. Gases generated from oil and insulation breakdown offer insights into asset management and grid reliability. Stray gassing, caused by the fluid or additives like passivators, should be considered to avoid misinterpreting in-service data. Table 4 presents norms based on survey data, helping identify oils prone to stray gassing through tests in high oxygen and high nitrogen environments simulating different service conditions.
Dissolved Gas Analysis (DGA) is a crucial test for monitoring electrical asset performance during service. Gases generated from oil and insulation breakdown offer insights into asset management and grid reliability
Table 4: Stray Gassing Norms TOPS
Oils with passivator added can show a greater tendency to produce higher than normal concentrations of some gases, typically hydrogen and carbon monoxide, which are formed at lower temperatures. Concentrations of Hydrogen from survey oils tested is shown in Figures 12, with the concentration of passivator shown for any oil that had detectable concentrations of BTA or Irgamet 39.
Figure 10: Stray Gassing Hydrogen Air Sparged
Composition
Mineral transformer oils can be sourced from naphthenic, paraffinic, or natural gas, each with distinct properties due to the hydrocarbon composition. Naphthenic oils have fewer waxy compounds and are refined using solvent extraction and hydrotreating, which produces a base oil that is receptive to oxidation inhibitor additives. The refining process needs to allow some aromatics, which are natural inhibitors, to be retained in those oils that will not have synthetic inhibitors added (Uninhibited products).
Highly refined paraffinic oils produced using hydroprocessing, which removes waxy components and undesirable compounds such as sulfur and nitrogen, have very low aromatic contents and typically have lower specific gravity and viscosity than naphthenic oil. This lower viscosity can be most evident at lower temperatures.
Gas-to-liquid (GTL) oils, derived from methane, are almost entirely isoparaffinic and without added aromatics have very high gassing tendency values. Flash point is influenced by the volatile compounds in an oil and iso-paraffins tend to be well in excess of the 145°C minimum specified by TOPS. This limit may be reviewed in the next revision of TOPS. Extended rotating pressure vessel times are also a typical feature of iso-paraffin oils.
Properties of oils from various sources are detailed in Table 5:
Table 5: Properties of oils from different sources
Summary
In summary, there are many oils in the market from different crude sources and specifications should be employed to help you evaluate them. Advances in refining processes result in changes over time and specifications need to keep up with these changes so that they remain relevant. Oils from these various sources are generally fully miscible and compatible with one another, with the caveat that when replacing an oil in service with one that has a significantly different aromatic content, may lead to gasket issues, impacting seal effectiveness.
In summary, there are many oils in the market from different crude sources and specifications should be employed to help you evaluate them. Advances in refining processes result in changes over time, and specifications need to keep up with these changes so that they remain relevant.
Eileen Finnan, currently holds the position of Senior Director, Professional Services at Doble Engineering where she is responsible for transformer consulting, field testing, and insulating and high voltage laboratory services in the US. She has participated for many years in cross-functional teams that deliver in-depth condition assessments of critical electrical assets and large-scale fleet assessment services. Her previous roles include Manager at Doble Engineering Materials Laboratory which provides routine and specialized testing on insulating fluids from electric power equipment. Eileen currently has responsibility for issuing the Doble Annual Survey which evaluates commercially available domestic and international transformer oils. She is a frequent presenter of Doble’s Laboratory Diagnostics Seminar. Eileen received her Bachelor of Science degree in Physics and Chemistry from Trinity College in Dublin, Ireland.