Automation allows continuous measurement through multi-phase metering

Almost every offshore pipeline will have multi-phase flow. Whether that flow is two or more phases, this will always mean measurement difficulties since all direct flow measurement techniques are based on single-phase fluids.

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Ian Verhappen
Industrial Automation Networks Inc.

Almost every offshore pipeline will have multi-phase flow. Whether that flow is two or more phases, this will always mean measurement difficulties since all direct flow measurement techniques are based on single-phase fluids. Liquid/liquid flow is certainly easier to measure than gas/liquid flow. However, almost all subsea gas wells will, for at least part of the lines connecting them to the surface, experience multi-phase flow. Multi-phase flow is highly reliant on automation to provide information of a quality that can be used for mass balance and, preferably, custody transfer (accounting) purposes.

Fortunately, with the advances in microprocessors, automation technology now allows multi-phase meters to continuously measure gas, oil, and water without physically separating the fluid stream into individual phases.

Pressure drop across multi-phase meters is significantly less than if streams were separated into individual phases and then recombined. This aligns the testing of individual wells close to actual producing conditions.

If commingling occurs through a subsea production manifold without a test line, measuring individual well performance requires testing by difference, which entails shutting in one of the wells while measuring the other. Once measuring is completed, data is derived for each well by difference. Deferred production and poor accuracy can result.

One separator typically costs $500,000; additionally, it adds weight and uses valuable platform space. Multi-phase meters are typically 40% of this amount, and are becoming a viable alternative.

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The following table summarizes the different flow patterns present in horizontal and vertical installations. Vertical installations with only five flow regimes are better delineated than horizontal configurations, making it the preferred method of installing multi-phase flow meters.

It is possible for the oil and water to separate in stratified flow and in slug flow, meaning that there will be slip between the two liquid phases. Therefore, when the pipe is oriented vertically, due to density differences, the liquid and gas travel at different velocities because of slip between the phases.

Phase fraction is a measure of the fraction of area occupied by the gas against the total area of the pipe cross section. The liquid phase is usually a mixture of oil and water. Hence, an additional measurement needs to be made to ascertain the amount of water and oil in the liquid. By calculating the measured phase fraction and the phase velocities, the volume flow rates for each of the phases can be quantified, meaning that a minimum of six parameters have to be measured or estimated.

In addition to the complexities of combining multiple technologies, there are also limitations to their use. These are imposed by the fluid properties themselves.

In multi-phase flow, the liquid either exists in what are called oil-continuous or water-continuous regimes. Oil-continuous flow is characterized by water droplets being surrounded by oil; water-continuous flow is oil droplets surrounded by water. When in an oil-continuous regime, the dielectric properties dominate, whereas in a water-continuous regime, the conductive properties dominate.

The inversion region lies between oil-continuous and water-continuous flow and is unpredictable, as it can show characteristics of either oil-continuous or water-continuous flow, changing from one moment to the next. Operating in the oil- or water-inversion region can create difficulties for certain multi-phase measurement technologies.

Normally, the flow is oil-continuous as long as the water cut is below approximately 60-70%. Capacitance measurement works as the way to determine water-oil ratio. In water-continuous phases, the capacitance measurement is normally replaced by a conductivity measurement.

There are two main types of gamma ray attenuation used in multi-phase flow meters: single high energy, which distinguishes the gas from the liquid, and dual (high and low) energy, which uses the low energy gamma rays for differentiating the oil from the water.

Since volume is the product of velocity and cross-sectional area, the most important measurement is velocity. Velocity measurements by cross-correlation are a standard signal processing method to determine the velocity of flows. Some properties of the flow are measured by two identical sensors at two different locations in the meter, separated by a known distance. As the flow passes the two sensors, the signal pattern measured by the first sensor will be repeated at the downstream sensor after a short period of time, corresponding to the time it takes the flow to travel from the first to the second sensor. The signals from the two sensors can be input to a cross-correlation routine, which moves the signal trace of the second sensor over the signal trace of the first sensor in time. The time-shift that gives the best match between the two signals corresponds to the time it takes the flow to travel between the sensors. Knowing the distance between the sensors, it is therefore possible to calculate the flow velocity.

Whatever method of multi-phase flow measurement is chosen, some additional issues and challenges can affect the measurement accuracy.

Multi-phase flow measurement is not yet at the same state as single phase flow technology, however it is rapidly improving. In the majority of cases, it presents a more viable option than other alternatives. As with many new technologies, however, the challenge lies in changing the culture. Remember, one can only manage what one can measure. Automation technology is able to help manage production flow with all the associated benefits, although it requires investment. •

The author

Ian Verhappen, P.Eng. is an ISA Fellow, ISA Certified Automation Professional (CAP), Automation Hall of Fame member and a recognized authority on process analyzer sample systems, Foundation Fieldbus and industrial communications technologies. Verhappen provides consulting services in the areas of field level industrial communications, process analytics and hydrocarbon facility automation. Feedback is always welcome via e-mail

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