Tim Patten is the director of measurement technology for Micro Motion Inc., a division of Emerson Process Management. He has 22 years experience in fluid handling systems (compressors, pumps, and flow measurement) and has been with Micro Motion for 17 years, working in a variety of test and evaluation, design, and engineering management positions. Mr. Patten earned a master’s degree in Mechanical Engineering from Worcester Polytechnic Institute and a bachelor’s degree in Mining Engineering from Colorado School of Mines. He can be reached at tim.patten@emersonprocess.com.


Q: What is multiphase flow, and what makes multiphase flow such a difficult measurement?

A: Multiphase measurement is a catch-all term that describes multiple fluid components in a flowing stream. For instance, water and oil are considered to be multiphase in the oil and gas industry, even though they are both liquids. Slurries are truly multiphase because there are liquid and solid components. Usually, multiphase measurements that are made up of multiple liquid components or slurries are “easy” to measure. This is because the fluid is homogenous and it behaves as if it is a single component.

Difficult multiphase measurements usually involve a liquid and a gas, such as water and air. Measurement difficulties arise because the gas tends to separate from the liquid, creating a non-homogenous fluid.


Q: In what types of applications is multiphase flow typically found?

First, let’s consider multiphase to mean liquid with a gas entrained. Multiphase applications fall into three main categories:
• Fluids where gas is entrained on purpose (ice cream)
• Fluids where gas occurs as part of the process (production of crude oil, water, and natural gas)
• Fluids where gas is not part of the process, but is in the fluid anyway. This category can be broken into two sub-categories:
– Fluids where it does not matter that gas is entrained (railcar loading)
– Fluids where it matters, and the gas is an upset condition (emulsion coating of film)

How gas gets into the liquid in the first two applications is self-evident. The last application, where gas is not intended to be part of the process, deserves some elaboration. Gas can be entrained a number of ways:
• Mixing in an open tank can mix air into the liquid;
• Low tank level on the suction of a pump;
• Leaking pump seals; and
• A vacuum on a liquid can “pull” the air out of solution. This is a similar phenomenon to flashing (and subsequently cavitation).

The most common way for air to enter a liquid stream is on a process line where multiple products are transferred. Commonly, it is desired to keep the products from cross-contaminating each other, so the line is blown out with air or inert gas in between the different products.


Q: What are some common solutions for measuring multiphase flow?

A: The most common solution to measuring multiphase flow streams is to first separate the phases. Again, this usually means separating the gas phase from the liquid phase(s), then measuring the gas and liquid separately. A very common application for Coriolis flowmeters, which are particularly well suited for multiphase scenarios, is on an oil well separator. The separator can be as simple as a big tank where the residence time is long. Eventually, the pure gas phase rises from the top of the tank and the liquids (oil and water) are extracted from the bottom of the tank. By using the flow and density measurements of a Coriolis meter, the net oil and net water flowrates can be provided.

In some cases, mixing the fluid well provides enough homogeneity that it can be measured. Fluids that tend to emulsify often can be mixed and measured accurately.
It is a common belief that volumetric meters, such as magnetic flowmeters, measure multiphase streams accurately with little or no modification to the meter or the process; this is only partially true. First, remember that all volumetric meters measure the velocity (in one way or another). Now assume there are two flow streams with equal mass flowrates between them, but the second stream has 1 percent (by volume) air entrained. Since the mass flow of the two streams is the same, the velocity of the second stream must be 1 percent higher (assuming the air has negligible mass flowrate). A volumetric meter will indicate the velocity properly; however, if the velocity of the liquid-only part of the stream is of interest, the meter will over-indicate by 1 percent. This example points out the need to assess what measurement is desired; if measurement of the liquid-only component of a process is important, considerations for separating the gas may be important.


Q: Why is recalibration and maintenance of particular concern in multiphase flow measurement environments?

A: Many measurement technologies can be damaged by air. Mechanical meters, for instance, will show premature wear if gas is in the system because the lubricity of the fluid is less. Also, large “slugs” of air can cause catastrophic damage to meters, requiring complete replacement in some cases.


Q: What makes Coriolis flowmetering systems such a good fit for multiphase flow? What does Coriolis technology offer that other flowmeter technologies don”t in terms of capability to measure multiphase flow?

A: Coriolis meters are ideal for multiphase measurement because they measure mass flow. For example, assume there is 1 percent air entrained in a liquid pipeline. The air usually represents a very small (less than 0.01 percent) portion of the total mass flow. Unlike a volumetric meter that measures velocity, Coriolis meters measure the mass flow and therefore “ignore” the air in the system, giving an accurate measurement of the liquid-only component.

Coriolis meters have no moving parts to be damaged by poor lubricity or gas slugs. Recalibration and maintenance concerns are minimized (or eliminated) with Coriolis meters.


Q: How do you see multiphase flow measurement systems evolving going forward? What improvements might users be able to look forward to in terms of new technologies for multiphase flow measurement?

A: Multiphase measurement, if defined to be air entrained in a single-phase liquid and the liquid-only mass flow measurement is desired, is largely addressed by current Coriolis meter technology. This is especially true if entrained air levels are less than 5 percent.

A more generalized definition of multiphase measurement requires a multi-instrument solution. Many times there are three (or more) fluid components in an application and it is desired to calculate the net flow of each component. Oil, water, and natural gas at a well head is one of the most common measurements, and one that has garnered attention from oil companies for years. It is unlikely that a single device can make enough measurements to calculate the flow of each component, but by bundling measurements together it may be possible to provide accurate measurements of each component.

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