The effect of salinity on foam formation was studied using an internal olefin sulfonate surfactant through a core of Berea sandstone of 255 mD at 0.4 mL/min and pressures of 400 and 500 psi. The apparent viscosity of foam decreased with increasing salinity due to decrease of foamability in the range of 1–5% NaCl. Due to preheating of the surfactant solution in the oven, it was higher at 6% and 8% NaCl than at 5% NaCl. The phenomena observed are in stark contrast to what is reported in many publications, the apparent viscosity against foam quality demonstrated a Newtonian plateau in low-quality regime at 1, 4 and 6% NaCl. The apparent viscosity linearly decreased at 5% and 8% NaCl while foam was not produced at 9–11% NaCl. A significant decrease in differential pressure, which implied an increase in pressure, was measured near the end of the core sample, mainly at 400 psi. Accumulation of trapped gas that was unable to exit due to slower gas flow explains these findings. A novel technique of using the length of foam drops at the system outlet as an indicator of the foam viscosity has been applied to determine governing factors of the foam flow, such as the liquid flow rate in low quality regime and gas flow rate in high quality regime.
- Apparent viscosity
- Drop length
ASJC Scopus subject areas
- Fuel Technology
- Geotechnical Engineering and Engineering Geology
- Energy Engineering and Power Technology