Foam stability characterization and performance in the presence of surfactant for gas well deliquification

Abstract

In gas well deliquification, surfactant injection minimises liquid loading in mature gas wells, promoting a stable gas output. It is critical to evaluate the surfactant performance and produced foam stability. To this end, laboratory experiments are conducted to determine the surfactant’s performance. This study focused on the characterisation study of foam stability and quantify the quantify the foam unloading capacity at different field formation water salinity, temperature, and field hydrocarbon ratios. The foam stability at different field hydrocarbon ratios reduces as the hydrocarbon ratio increases. At 15% and 50% hydrocarbon ratio, the full time collapse is at 203 seconds and 100 seconds. More stable foam is observed as the water salinity increases. It is recorded at 9.85 ppt, showing the full time collapse at 420 seconds, while at 6.31ppt, the full time collapse at 329 seconds. The increase in testing temperature to 90°C shows the lowest foam stability with 140 seconds of full collapse. At 4°C shows 450 seconds of full collapse. In conclusion, the more stable foam formed at higher water salinity. Adding hydrocarbon in the water ratio acts like defoamer agent to reduce the foam stability. At high temperature, foam collapse the fastest as compared to other parameters, with 70 seconds of full collapse at 329 seconds. Based on the unloading performance, at low hydrocatbon ratio, high salinity, and low temperature able have the excellent unloading performance as more stable foam able to entraine the fluids over the testing column.