Abstract
The estimation of pressure drop for multiphase flow in a vertical pipe is one of the more complex problems in oil field practice. The most successful solutions to this problem involve trial and error calculations in problem involve trial and error calculations in subdivided sections of flow patterns. No two methods yield identical results for a given set of flow conditions as the multiphase flow problem is extremely difficult to analyze. Fortunately the introduction of the computer in the petroleum industry has enhanced the investigation of the multiphase flow problem. Rapid computation provides a means for comparison of individual provides a means for comparison of individual methods and an instrument for the development of new correlations. Three of the best correlations were chosen and evaluated; the Hagedorn and Brown, Duns and Ros, and Orkiszewski methods. The accuracy of these new correlations was determined against multiphase flow pressure drop data from 44 wells. The best solution which was both general and gave satisfactory accuracy for all possible ranges of well conditions was determined. The method of Orkiszewski was found to be most accurate for engineering design usage and was the only correlation which could evaluate a three phase flow condition when water is simultaneously being produced with the gas-oil mixture.
Introduction
Accurate prediction of the pressure drop to be encountered during the multiphase flow of fluids in a vertical well is desired for good engineering data. The lack of reliable pressure drop data and experimental flow pressure drop data and experimental flow apparatus for correlation data gathering represent the inherent problems of obtaining a general multiphase flow model. During multiphase flow in vertical tubing at least four distinct regimes of flow are identifiable. These are usually described as the bubble, slug, transition, and mist flow regions. Figure 1 illustrates the geometrical configuration of the four regions of flow. Bubble flow consists of a continuous liquid phase with little free gas present. As greater quantities of gas evolve present. As greater quantities of gas evolve from the liquid phase, the gas bubbles agglomerate, forming slug-like gas pockets characteristic of the slug flow region. As still greater amounts of gas are released, the transition flow region forms in which droplets of liquid become entrained in the gas pockets. The gas pockets become distorted and approach a continuous gas form.
