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Title: An Investigation Into Multiphase Flow Streams Containing A Viscous Oil Component
Author: Christopher Mills Neil Barton, Richard Harvey, Amy Ross And Gary Miller, Andrew Parry, Cheng-Gang Xie And Bruno Pinguet
Source: 2009 South East Asia Flow Measurement Conference
Year Published: 2009
Abstract: Complex multiphase fluids, such as those containing viscous liquid components, arise in many industrial fields although it is within the upstream hydrocarbon production industry, in particular the growing heavy-oil sector, that most focus is being placed on their measurement. On a global basis, around seventy per-cent of the worlds remaining oil reserves are estimated to be in the heavy or extra-heavy category. That means that their density is below 22.3 API and their in-situ viscosity within the range 100 - 10000 cP. Tar sands and bitumen deposits have higher viscosities still. There is a growing need to properly quantify these high viscosity crudes, which in virtually all cases are produced and transported as complex multiphase flow streams containing gas, heavy-oil and water. In these heavier oil environments, traditional test separators can no longer provide a sufficient level of measurement accuracy, due to the higher densities and higher viscosities involved. Multiphase flow meters (MPFMs), on the other hand, have reached a level of technical development where they are regarded as acceptable alternatives to test separators in many hydrocarbon exploration and production applications and the challenge now exists to further extend their capabilities into higher-viscosity regimes. Multiphase flow meters (MPFMs) combine a number of primary sensors, which are used to measure physical parameters such as pressure, temperature, water-cut, density, and fluid velocity. For many such sensors, the output signals have a strong dependence on the structure of the flow (the flow regime), and models are required to decode and interpret the signals correctly. To date, most of the flow models used with commercial MPFMs have been developed for conventional crude-oil production applications, and hence are applicable for relatively lowviscosity liquid / gas flow regimes. As the liquid viscosity rises, the extent to which the classic flow patterns (stratified, slug, bubbly, annular etc.) change, and under what conditions, has yet to be firmly established. Consequently, the extent to which the flow models must also be adjusted or developed remains similarly unclear.

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