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1 May 2006

Dynamic oil system holds quirks

While the traditional unit of measure for expressing moisture content in fluids is ppm, water activity is more complete

By Steven Jiroutek and Nicholas Sheble

The online measurement of moisture in oil is essential to realize a comprehensive, predictive maintenance program for transformers.

Maintenance costs in the automation subsets of power turbines, paper machines, and factory ware using lubricating oils to fight corrosion are all lower when vigilant monitoring of water in oil is regular.

Every fluid has the ability to hold a certain amount of dissolved water.

The maximum amount of water that a given fluid can contain in solution is its saturation point. Once the fluid has reached its saturation point, any additional water introduced will separate out as free water by forming a distinct layer.

Since most oils are less dense than water, the water layer will usually settle below the oil.

Oil's saturation point is a function of many different factors, such as the composition of its base stock (mineral or synthetic), as well as the type of additives, emulsifiers, and oxidizing agents present. Aside from these initial composition differences, the saturation point of oil will vary over its lifetime as a working fluid.

Two major factors that influence oil's saturation point as it ages are fluctuations in temperature as well as changes in chemical makeup due to the formation of new substances produced as by-products of chemical reactions taking place within a dynamic oil system.

The traditional unit of measure for quantifying water content in oil has been parts per million (ppm). What is the significance of a ppm measurement? By definition, ppm is an absolute moisture parameter that describes the volume or mass ratio of water to oil.

By volume: 1 ppm (volume) water = 1 gallon of water / 1,000,000 gallons of oil

or

By mass: 1 ppm (mass) water = 1 lb. of water / 1,000,000 lbs. of oil.

By actively measuring ppm levels of water in oil, the absolute amount of water can be determined. However, a ppm measurement has one major limitation—it does not account for any variation in oil's saturation point.

In other words, in a dynamic oil system with a fluctuating saturation point, a ppm measurement would provide no indication of how close the moisture level is to the oil's saturation point.

This becomes even more critical when the water content nears the oil's saturation point, creating a risk of actually exceeding the saturation point and forming free water—a destructive contaminant to almost all oil applications.

To illustrate this concept, consider oil that undergoes a 100°F (38ºC) reduction in temperature.

This shows the saturation point of the oil at 180°F (82ºC) is 5000 ppm. The amount of water in this oil is 2000 ppm. This means the oil can hold another 3000 ppm more water before the oil becomes saturated. This is the margin to the saturation point.

When the temperature of this oil drops to 80°F (27º C), the saturation point of the oil also drops to 3000 ppm. Note: The amount of water in the oil has not changed (still 2000 ppm); however, the margin to the saturation point has dropped to 1000 ppm.

In this scenario, if an operator were only measuring ppm, he would see no change for water present (2000 ppm) even though the margin has dropped dramatically and the saturation point has moved much closer to the water content, creating a greater risk of free water formation.

What would happen if after one year, due to aging of the oil, the saturation point went down further to 1500 ppm?

In this scenario, there is no longer a margin to saturation since the water content is now greater than the saturation point. As before, an operator would continue to read moisture content of 2000 ppm despite the fact that the saturation point has now gone down to 1500 ppm resulting in 500 ppm of free water formation.

Providing a true indication

By measuring water activity instead of ppm, the user can avoid the uncertainty of the above problems.

What is water activity (a_w)? It is the amount of water in a substance relative to the total amount of water it can hold and mathematically figures as a_w = p / p₀.

Where:

p = The partial pressure of water in a substance above the material

p₀ = The saturated vapor pressure of pure water at the same temperature

In the example, a_w changes as a function of the saturation point (p0, the denominator). a_w will also change as a function of actual water content in the oil (i.e., water entering or leaving the oil). In other words, a_w will always provide a true indication of the margin to saturation point.

While it is possible to derive a correlation between a_w and ppm for any oil, the validity of this relationship over its lifetime in a dynamic oil system (e.g., lubricating oil) will diminish. With age, a fluid undergoes changes in composition due to chemical reactions taking place, which not only affect its saturation point but also its relationship to aw.

Here is this phenomenon in graphic form:

Independent of the fluid

While there are many different methods of measuring moisture in oil available in today's market, the latest in-line, water-activity measurement technology uses a capacitive-type sensor that operates on an absorption principle.

The sensor is a capacitor consisting of an upper and lower electrode with an insulating material in between known as a dielectric. The dielectric absorbs and desorbs water molecules, changing the dielectric constant and thereby the capacitance of the sensor.

Water absorption is proportional to water activity of the fluid. The benefits associated with this type of technology are the ability for direct in-line installation, a fast response time, and good chemical durability suitable for a wide range of fluids.

Good candidates for this in-line technology include applications involving large oil or hydraulic systems, such as paper machine lubrication, turbine and transformer operation, and oil-reclamation system manufacturers.

With many manufacturing facilities today employing some type of predictive maintenance program designed to prevent machine downtime and extend equipment life, an in-line, continuous moisture measurement becomes an integral part of this fluid management plan.

While the traditional unit of measure for expressing moisture content in fluids has been ppm, measuring aw can offer a more complete picture of the condition of a fluid.

1. Regardless of the saturation point of the fluid, an aw reading will always provide a true indication of risk of free water formation.

2. As the saturation point increases or decreases for whatever reason (e.g., temperature, age, change in physical properties), aw accurately reflects the new margin to saturation.

3. a_w is independent of the fluid under study. Since aw applies to all fluids and solids, it can be used universally for all substances regardless of chemical composition or physical characteristics.

ABOUT THE AUTHORS

Steven Jiroutek (steven.jiroutek@vaisala.com) has a degree in chemical engineering and works with Vaisala as an application engineer specializing in moisture-in-oil and dew point instrumentation.