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This work study pore-level oil mobilization by water diffusion and osmosis during low salinity waterflooding using microscopic visualization in sandstone silicon-wafer micromodels. The twodimensional water-wet micromodels apply a high accuracy pore network with sharp edges and surface roughness to observe displacement processes during low salinity water injection. Residual and capillary trapped oil was mobilized when a salinity gradient between high-saline connate water in matrix and low salinity water flowing in an adjacent fracture was established. Transport of water by diffusion occurred through film-flow resulting in film-expansion and droplet growth along the water-wet grains. Water transport was also driven by osmosis due to the difference in chemical potential between the high and low-saline phases. The oil-phase acted as a semi-permeable membrane in presence of an osmotic gradient to transport low salinity water into high-saline water-in-oil emulsions. The identified pore-scale displacement mechanisms, observed using a controlled state-of-the-art experimental approach, contribute to the fundamental understanding of improved oil recovery during low salinity waterflooding.

Summary A carbon–dioxide (CO2) –foam enhanced–oil–recovery (EOR) field pilot research program has been started to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic–CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a comprehensive integrated multiscale methodology is required for project design to better link laboratory– and field–scale displacement mechanisms. This study presents an integrated upscaling approach for designing a miscible CO2–foam field trial, including pilot–well–selection criteria and laboratory corefloods combined with reservoir–scale simulation to offer recommendations for the injection of alternating slugs of surfactant solution and CO2, or surfactant–alternating–gas (SAG) injection, while assessing CO2–storage potential. Laboratory investigations include dynamic aging, foam–stability scans, CO2–foam EOR corefloods with associated CO2 storage, and unsteady–state CO2/water endpoint relative permeability measurements. Tertiary CO2–foam EOR corefloods at oil–wet conditions result in a total recovery factor of 80% of original oil in place (OOIP), with an incremental recovery of 30% of OOIP by CO2 foam after waterflooding. Stable CO2 foam, using aqueous surfactants with a gas fraction of 0.70, provided mobility–reduction factors (MRFs) up to 340 compared with pure–CO2 injection at reservoir conditions. Oil recovery, gas–mobility reduction, producing–gas/oil ratio (GOR), and CO2 utilization at field pilot scale were investigated with a validated numerical model. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.

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