Study of the flow pattern and pressure drop law of the air-water-foam three-phase flow

The inaccurate prediction of flow patterns and pressures after adding different types and concentrations of surfactants to wellbores and drainage lines is a common problem in shale gas wells and tubing foam drainage. To clarify the change rule of the air–water-foam three-phase flow pattern and pressure drop after adding different types and concentrations of surfactants, a surface tension test was conducted in this study. In addition, visual air–water-foam three-phase flow indoor simulation experiments were performed with various surfactants such as cocamidopropyl hydroxysulfobetaine (MX-1), dodecyldimethyl betaine (TCJ-1), and sodium α-alkenyl sulfonate (XJHSM), surfactant concentrations (0.3–0.6 %), oil pipe diameters, pipe inclinations, gas–liquid ratios, and oil contents on large-scale experimental equipment. Based on the gas–liquid distribution characteristics, the air–water-foam three-phase flow patterns in the inclined tube were reclassified, and the quantitative conversion boundaries of the various flow patterns were determined. Based on the pressure drop pulse characteristics, characterization parameters such as the scaling factor, foaming capacity, foam density, and gas-holding rate were introduced after considering the effects of various factors on the pressure drop weights, enabling a new pressure drop calculation method for air–water-foam three-phase flows for application to different types and concentrations of surfactants. The errors were verified using data from previous studies and field measurements that were within 15% and 5%, respectively. The results of these studies provide a better understanding of the air–water-foam three-phase flow patterns and pressure drop variations in shale gas wells and gathering lines.