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Viscosity can go up, down or remain unchanged. The list of root causes that can alter a viscosity reading is quite extensive; hence the reason why viscosity has become such an information-rich measure of used oil condition. After all, when viscosity has not changed, you can rightly conclude that the many known viscosity-altering factors are probably not happening - a good thing for sure.
What's not so good is when viscosity moves suddenly with no obvious explanation or warning. What does it mean and why did it occur? This column explores the many possible causes of downward-trending viscosity. Upward trends will be covered in an upcoming issue of the magazine.
It's safe to say that viscosity will not change without a forcing event or condition that incites the change. The oil analysis community is aware of the usual suspect conditions or events, but some remain undiscovered or at least are not fully understood. When it comes to an abrupt loss of viscosity or a downward viscosity movement, the following are common contributing factors that we now know:
Lubricant viscosity can be thinned or cut back by adding a low-viscosity fluid or dissolved gas to the mix. This type of blending is often performed by formulators and blend plants to bring a high-viscosity oil into a target viscosity grade (ISO VG 46, for instance) of a branded product.
In plant or field equipment, this could happen when a low-viscosity lubricant is accidentally used as makeup fluid which drops viscosity through dilution. Also, when certain nonlubricants contaminate a fluid, a similar end result occurs. Examples of such contaminants include natural gas, solvents, diesel fuel, degreasers, process chemicals and refrigerants.
The selective removal of high molecular-weight suspensions in a lubricant is less common, but still plausible. This would cause a loss of viscosity because it would destabilize the blend. The following are a few examples of how this could occur:
These high molecular-weight polymer additives used in many lubricant formulations may become separated from the base oil due to (1) insolubility by sustained exposure to very cold temperature, (2) insolubility when mixed with an incompatible base oil (such as olefin copolymers in Group II base oils for instance), or by (3) mechanical filtration (at higher temperatures, some VII are said to be able to plug extremely fine filters).
Many contaminants and soft impurities that might have originally elevated viscosity can later be removed, causing a noticeable drop in viscosity. These include waxy suspensions, sludge, oxide insolubles, decomposed additives, soot and gels. Such impurities can separate or stratify from the oil due to cold temperature insolvency, loss of dispersancy, chemical coagulation/agglomeration or water washing.
The separation can occur during storage, centrifugation or filtration, but in other cases may simply form sludge zones in tanks or become released to form deposits, varnish or reservoir bathtub rings.
Mass change is probably the most common explanation for a low-viscosity reading and can occur due to numerous mechanical, electrical and chemical reasons. Because the viscosity of an oil can be referred to as the average molecular weight of an oil's blended population of molecules, viscosity will decrease when large molecules break into numerous smaller molecules (like crushing a rock into gravel). Let's look at the several possibilities:
Some VIIs have molecular weights ranging more than one million. After exposure to mechanical shear within a machine, the average MW of these VIIs can fall to 50,000 or less. This is influenced by the quality of VII, its concentration in the oil, the oil's operating temperature and the shear rate. High temperature will swell the VII molecule, making it more vulnerable to shear.
Arcing electricity can occur for several reasons including improperly grounded electric motors/generators, welding activities and electrostatic discharge. These high-temperature events can fracture molecules resulting in gas evolution (release into the oil), causing a loss of viscosity.
Oils exposed to high localized temperatures can crack oil molecules into progressively smaller fragments which thins viscosity considerably. Common examples are microdieseling, hot spots (for instance, leaky steam flowing across on oil line), high Watt-density heater elements, and close-proximity furnaces.
Prolonged exposure to high doses of gamma radiation can cause molecular cleavage and loss of viscosity. Risk is limited to nuclear power plants and is generally rare.
Certain ester-type synthetic lubricants, when contaminated with heat and water, can hydrolyze. High-risk lubricants include phosphate esters, diesters and polyol esters. Hydrolysis can occur at temperatures as low as 90°C, forming low molecular weight by-products, mostly acids and alcohols.
Some PAO synthetics and high-quality mineral oils may be formulated with diesters to improve additive solubility and control seal shrinkage. Low-viscosity diesters have the highest risk of hydrolysis.
Of course, there are a variety of ways machines can be sampled incorrectly or sample bottles mislabeled that could trip a low-viscosity alarm. Similar errors can occur when samples arrive at the laboratory and are wrongly logged for processing. And of course, mistakes in preparing samples, viscometer operation or viscometers that are out of calibration can all lead to falsely reported low-viscosity measurements. Sometimes the problem is a new-oil baseline error (wrongly measured new-oil viscosity; too high) as opposed to the trended in-service oil.
The best way to confirm the cause of a low-viscosity reading is to look at other oil analysis data or perform exception tests designed to isolate the problem. Depending on the suspect cause, many possible confirming tests could be used for this purpose. As with machines that fail suddenly, root cause analysis (RCA) of problem viscosity readings can be equally important. Ask the "repetitive why" to find and correct the underlying cause to avoid reoccurrence.