Study of enhanced oil recovery using polymer-stabilised CO2-Foam

CO2 is one of the most widely used gases in flooding processes due to solubility of CO2 in oil that can efficiently reduce oil viscosity at reservoir pressure. However, low viscosity of CO2 gas, results in early gas breakthrough, poor sweep efficiency, viscous fingering, and channelling that result in low oil recovery. Due to low viscosity, gases tend to have higher mobility than oil and water which leads to gravity override and channelling through oil in the rocks. This decreases the amount of oil being (Xu et. al., 2017). Foam flooding processes have been used successfully for more than 6 decays, but more work has to be done to better understand and optimize the process for successful field implementation. Foam is an EOR technique that significantly can improve the macroscopic sweep efficiency by lowering the gas mobility. Due to limited stability of conventional surfactants for foam generation, foam is not being widely used as a common EOR technique. One proposed approach for foam stabilization is the addition of polymers, so called polymer enhanced foam. Hydrophobically modified polyacrylamide is a type of associative polymers that has been introduced to oil field applications as an alternative to conventional HPAM for the past two decades. The main characteristics of these polymers are their significant enhancement of solution viscosity, salinity tolerance and temperature resistance in comparison with conventional polymers such as HPAM, which would be more important in real applications. The aim of this project was to study the effect of novel phenyl-polyacrylamide (PPAM)- a hydrophobically modified polyacrylamide- as a potential viscosifier in foam flooding process. The two main objectives of this work were to study the change in the rheological behavior of polymeric foam in rocks with differing morphological properties, namely permeability and heterogeneity. Also, to study the effect of hydrophobically modified polymer on oil displacement. Based on the results of sand pack floods, it was concluded that permeability and type of polymer govern the trend of apparent viscosity growth and decay for a given sand permeability. The permeability of the sand had significantly influenced the foam viscosity, it was concluded that the heterogeneity of a sand pack does affect foam dynamics. Oil displacement tests were further conducted through consolidated core samples (Benthemier sandstone). Greater mobility reduction was observed for PPAM foam. This can be due to its larger molecular structure in solution which increases polymer viscosity. The core flooding results indicated that PPAM-foam resulted in higher oil recovery compared to HPAM-foam and surfactant foam, at the same condition. Viscosity reduction of PPAM foam in core flood test for sandstone was lower than HPAM foam at the same conditions. Therefore, it can be considered as a good candidate for EOR at reservoir condition