Partially hydrolyzed polyacrylamide (HPAM) is by far the most used synthetic polymer in enhanced oil recovery (EOR) projects. Shortcomings of HPAM include a highly molecular weight (M w) dependent viscosity yield and decreasing viscosifying ability with increasing salinity and temperature. For an economically viable project, this limits its use to reservoirs with low to moderate salinities and temperatures. In that respect, hydrophobically modified polyacrylamides (HMPAM) has been suggested as an alternative for applications at higher salinities and temperatures. While studies have compared the performance of modified versus unmodified commercial EOR polymers at different salinities and temperatures, and the structure–property relationship of monodisperse, low M w HMPAM, published data on the simultaneous effect of polymer hydrophobicity, salinity, and temperature for commercial EOR polymers are limited. This study thus presents a comprehensive series of experiments to investigate the effect of polymer hydrophobicity on viscosifying ability as a function of salinity and temperature. The main findings of these experiments are that the balance between salinity effects and thermal behavior shifts the order of viscosifying ability so that the polymer with the best viscosifying abilities at low temperatures and salinities is outperformed at conditions of high salinity and temperature. This highlights the importance of structure–activity studies at relevant reservoir conditions prior to selection of a solution for field application.

Hydrophobically modified polyelectrolytes have been suggested as an alternative to the more commonly used polyelectrolytes in enhanced oil recovery (EOR) applications involving polymers. Compared to regular polyelectrolytes, the hydrophobically modified polyelectrolytes are known to be more stable at high salinities. In this study, we have investigated the influence of brine salinity and ionic composition for a series of six hydrophobically modified polyelectrolytes with the same polymer backbone, but with an increasing average number of hydrophobic groups per polymer molecule. Polymer characterization has been performed using a combination of steady-state shear viscosity and dynamic oscillatory measurements. Hydrophobic interactions leading to a change in rheological properties was only observed above a threshold value for the concentration of hydrophobe. At the threshold value, saltinduced hydrophobic interactions were observed. For higher concentrations of hydrophobe, high salinity solutions showed one order of magnitude increase in viscosity compared to the polymer without hydrophobic groups. This could partly be explained by an increase in elasticity. These findings have important implications for polymer selection for EOR. V

Hydrophobically modified polyelectrolytes have been suggested as an alternative to the more commonly used polyelectrolytes in enhanced oil recovery (EOR) applications involving polymers. Compared to regular polyelectrolytes, the hydrophobically modified polyelectrolytes are known to be more stable at high salinities. In this study, we have investigated the influence of brine salinity and ionic composition for a series of six hydrophobically modified polyelectrolytes with the same polymer backbone, but with an increasing average number of hydrophobic groups per polymer molecule. Polymer characterization has been performed using a combination of steady-state shear viscosity and dynamic oscillatory measurements. Hydrophobic interactions leading to a change in rheological properties was only observed above a threshold value for the concentration of hydrophobe. At the threshold value, saltinduced hydrophobic interactions were observed. For higher concentrations of hydrophobe, high salinity solutions showed one order of magnitude increase in viscosity compared to the polymer without hydrophobic groups. This could partly be explained by an increase in elasticity. These findings have important implications for polymer selection for EOR. V C 2016 Wiley Periodicals, Inc. J. Appl.Polym. Sci. 2016, 133, 43520.

An integrated enhanced oil recovery (IEOR) approach is presented for fractured oil-wet carbonate reservoirs using surfactant pre-floods to alter wettability, establish conditions for capillary continuity and improve tertiary CO2 foam injections. Surfactant pre-floods, prior to CO2 foam injection, alter the wettability of fracture surface towards weakly water-wet conditions to reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity transmits differential pressure across fractures and increases both mobility control and viscous displacement during CO2 foam injection. Outcrop core plugs were aged to reflect conditions of an ongoing CO2 foam field pilot in West Texas. A range of surfactants were screened for their ability to change wetting state from oil-wet to water-wet. A cationic surfactant was the most effective in shifting the moderately oil-wet cores towards weakly water-wet conditions (from an Amott-Harvey index of - 0.56 ± 0.01 to 0.09 ± 0.02), and was used for pre-floods during IEOR. When applying a surfactant pre-flood in a fractured core system, 32 ± 4% points OOIP was additionally recovered by CO2 foam injection after secondary waterflooding. We argue the enhanced oil recovery is attributed to the surfactant successfully reducing the capillary entry pressure of the oil-wet matrix providing capillary continuity and enhancing volumetric sweep during tertiary CO2 foam injection.