Natural Gas Technology - Simultaneous Flow of Liquid and Gas Through Horizontal Pipe

A method is presented for predicting pressure drop for two-phase fluid flow in horizontal pipes. A set of 267 experimental measurements randomly sampled from approximately 1,000 measurements from various literature sources was used. Pressure gradients calculated by the procedure developed and compared with the experimental values showed a bias of +0.82 per cent and a standard deviation of 20.8 per cent. The advantatges of this method over other available methods of predicting two-phase flow pressure drop are (a) its comparative simplicity of application, (b) its relative independence of flow patterns, (c) its accuracy, which on the basis of a statistical evaluation predicts pressure drop closer than other available methods, and, (d) its ability to satisfactorily correlate laboratory data from various sources while the correlations from these sources do not appear to agree with one another. The method has been reduced to a simplified graphical procedure, suitable for field use. A two-phase f factor is defined and correlated with parameters involving the flowing gas-liquid mass ratio, a Reynolds number for the gas phase, and a Reynolds number for the liquid phase. The choice of parameters allows the correlation to reduce to the usual f factor plot for the limiting conditions of (111 gas or all liquid. INTRODUCTION The mechanics and characteristics of two-phase flow systems have been of interest throughout the industry for some time. In numerous engineering installations such as pipe lines, chemical reactors, and heat exchangers, two-phase flow conditions are of every day occurrence. In oil production operations it has been desirable, in some cases, to consider transporting gas and oil together in a common pipe from oil field to process plant. The trend toward centrally located stock tank batteries in oil fields has resulted in longer gathering pipelines in which more than one fluid phase is flowing. The increase in the producing capacity of oil wells due to new production tech- niques has created the need for review and re-design of many surface gathering lines for properly handling the increased production. Optimum pipe size for the situations described above has become an important factor. The problem which is of interest here involves the ability to predict the relationship between pressure drop, fluid properties, fluid rates, pipe diameter, and pipe length. Although the literature1,5,10,13,18,19 contains various articles dealing with specific cases of the problem, Lock-hart and Martinelli17 proposed the most general solution. Their method has been later modified by Baker:1 Alves2 demonstrated that different flow patterns are possible for a flow mechanism defined by Martinelli such as gas turbulent, liquid turbulent. Baker explained deviations experienced with Martinelli's correlations on the basis that different flow patterns could exist for the same flow mechanism. Using Martinelli's method of correlatioil, Baker correlated data for each flow pattern for the turbulent-turbulent flow mechanism. Bergelin and Gazley6,7 presented a correlation for predicting gas phase