In the second part of the paper, we show the application of a vertical multiphase flow model, developed from first principles. Estimation of gas void fraction, or mixture density - leading to pressure gradient estimates in each flow regime, and transition from one flow regime to another are modeled rigorously. An appropriate model is also used to handle flow in a tubing-casing annulus. Parameters, such as, tubing to casing diameter ratio and the equivalent diameter of the flow channel, developed from our experimental work, are incorporated in the model. Thus the model is capable of handling flow in both circular and annular channels.
Standard oilfield correlations are used for estimating PVT properties of oil and gas : Standing's correlation for solution gas-oil ratio; Katz's correlation for oil formation volume factor; Standing's, and Chew and Connally's correlations for dead and live oil viscosities, respectively; and Lee et al.'s correlation for gas viscosity.
Computation on test data gathered from some 115 oil wells, involving all the two-phase flow regimes, indicates that the proposed model performs better than the other models considered : Aziz et al., Orkiszewski, Duns and Ros, Beggs and Brill, Hagedorn and Brown, and Chierici et al. Calculations also reveal that bubbly and slug flow are the dominant flow mechanisms in most cases, while churn and annular flow are associated with high flow rate wells.
Hydrostatic head contributes to the most of the pressure drop (90 % +) when the flow is essentially restricted pressure drop (90 % +) when the flow is essentially restricted to the bubbly and slug flow. However, the frictional head becomes significant in annular flow. The test data bank used in this study is that previously used by other authors; thus, validation of the proposed model is made with an independent data set.
Predicting vertical multiphase flow behavior in oil and gas-condensate wells is of great practical significance and importance. Pressure losses encountered during cocurrent vertical flow of two- or three-phases enter into wide array of design calculations. Such design considerations include : tubing size and operating wellhead pressure in a flowing well; well completion or re-completion pressure in a flowing well; well completion or re-completion scheme; artificial lift during either gas-lift or pump operation in a low-energy reservoir; liquid unloading ill gas wells; direct input for surface flow line and equipment design calculations.
Efforts to predict the pressure drop in an oil well can be traced back to 1952 when Poettmann and Carpenter published their predictive scheme. Since then, many published their predictive scheme. Since then, many attempts have been made to predict the complex flow behavior starting from modification of Poettmann-Carpenter correlation to more complex mathematical models capable of handling flow hydrodynamics. To date, no single correlation or model can successfully predict pressure drop under the wide range of operating conditions encountered in wells around the world.