Abstract
Factors limiting foam injection for EOR application are exceptionally low rock permeability and exceedingly high salinity of the formation water. In this regard, foam formation using internal olefin sulfonate is investigated over a wide salinity range (1, 5, 8, 10, and 12% NaCl) through 10 mD limestone. The relationships between pressure drop (dP), apparent viscosity, liquid flow rate, total flow rate, salinity, foam texture, and length of foam drops at the outlet used as an indicator of viscosity are studied. Foaming is observed up to 12% NaCl, compared to a maximum of 8% NaCl in similar core-flooding experiments with 50 mD limestone and 255 mD sandstone. Thus, the salinity limit of foam formation has increased significantly due to the low permeability, which can be explained by the fact that the narrow porous system acts like a membrane with smaller holes. Compared to the increasing dP reported for highly permeable rocks, dP linearly decreases in almost the entire range of gas fraction (fg) at 1–10% NaCl. As fg increases, dP at higher total flow rate is higher at all salinities, but the magnitude of dP controls the dependence of apparent viscosity on total flow rate. Low dP is measured at 1% and 10% NaCl, and high dP is measured at 5, 8, and 12% NaCl. In the case of low dP, the apparent viscosity is higher at higher total flow rate with increasing gas fraction, but similar at two total flow rates with increasing liquid flow rate. In the case of high dP, the apparent viscosity is higher at lower total flow rate, both with an increase in the gas fraction and with an increase in the liquid flow rate. A linear correlation is found between dP or apparent viscosity and liquid flow rate, which defines it as a governing factor of foam flow and can be considered when modeling foam flow.
Highlights
Impact of salinity on foamability and foam stabilityThe main technologies of enhanced oil recovery (EOR) in carbonate reservoirs are C O2, N2, and hydrocarbon gas injections (Memon et al 2020)
The results of experiments in bubble column cannot be directly transferred to a foam flow through the porous medium, which is determined by several global factors such as fluids velocity, pregenerated foam texture, gas fraction, length of core sample, geometry of porous channels, and permeability (Nguyen et al 2000)
To investigate whether foam can form at even lower permeabilities, the salinity effect on foam flow through tight Indiana limestone of 10 mD permeability is presented for internal olefin sulfonate (IOS) in the range of 1–12% NaCl (10–120 g/L NaCl) and compared to similar experiments with 50 mD Indiana limestone
Summary
The main technologies of enhanced oil recovery (EOR) in carbonate reservoirs are C O2, N2, and hydrocarbon gas injections (Memon et al 2020). The choice of surfactants for foam injection depends on their ability to withstand the harsh conditions of oil reservoirs such as high salinity, temperature, and pressure. Increase in foam stability due to a decrease in the foam collapse rate in saline surfactant solutions has been shown in experimental studies using bubble columns, but the bubbles size and initial foam volume decrease (Varade and Ghosh 2017; Behera et al 2014; Nasr et al 2020). The results of experiments in bubble column cannot be directly transferred to a foam flow through the porous medium, which is determined by several global factors such as fluids velocity, pregenerated foam texture, gas fraction, length of core sample, geometry of porous channels, and permeability (Nguyen et al 2000). Apparent viscosity increases with increasing dP and permeability and decreasing velocity for the specific core sample. To investigate whether foam can form at even lower permeabilities, the salinity effect on foam flow through tight Indiana limestone of 10 mD permeability is presented for internal olefin sulfonate (IOS) in the range of 1–12% NaCl (10–120 g/L NaCl) and compared to similar experiments with 50 mD Indiana limestone
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