The impact of rock characteristics on the complex fluid-rock interactions is investigated MEs enhance the immiscible displacement (or mobilization) of NAPL by decreasing IFT and oil droplet size MEs promote the desorption of NAPL from rock surfaces (or solubilization) thereby altering their wettability At low concentration, MEs outperform surfactants in rocks containing carbonate cements
Summary
Controlled-ionic-composition waterflooding is an economic and effective method to improve oil recovery in carbonate oil reservoirs. Recent studies show controlling the salinity and ionic composition of injection water can alter the wettability of carbonate mineral surfaces. The pore-scale oil connectivity and displacement by controlled-ionic-composition waterflooding in heterogeneous carbonate reservoirs, especially at the early stage, is still unclear. The goal of this study is to examine the role of ion concentrations and types in the oil displacement efficiency and investigate the impact of the waterflooding on the pore-scale oil displacement using the national synchrotron facility. A carbonate rock sample was flooded with synthetic high-salinity water and other water solutions with different sulfate concentrations. The waterflooding processes were visualized with synchrotron X-ray microtomography to follow the evolution of pore-scale oil/brine interactions at typical field flow rates. Experimental results show that the water with lower sulfate concentration and higher salinity did not change the wettability of the pore surfaces. Higher sulfate ion concentrations in the water, in contrast, altered the wettability of carbonate pore surfaces from oil-wet to neutral-wet within the first few minutes of waterflooding. Novel insight was gained on the ability of water with high-sulfate concentration to displace oil in the small pores and through abundant oil channels, which could consequently lead to higher oil recovery from the carbonate rock.
This study consists of a pore-scale investigation of two-phase flow dynamics during nanofluid flooding in subsurface formations containing non-aqueous phase liquids (NAPLs) such as crude oils. The goal was to gain fundamental understanding of the dominant displacement mechanisms of NAPL at different stages of nanofluid injection in a carbonate rock using x-ray microtomography integrated with a miniature coreflooding system. The nanofluid consisted of surfactant-based microemulsions with in-situ synthesized silica nanoparticles. After establishing its initial wettability state, the carbonate core sample was subjected to various pore volumes (PV) of nanofluid flooding (from 0.5 to 10) to examine the impact on NAPL flow dynamics. We found that most NAPL mobilization occurred within the first PV of injection, removing nearly 50% of NAPL from the rock. The nanofluid invaded into larger pores first with piston-like displacement due to a sharp decrease in NAPL/brine interfacial tension (from 14 to 0.5 mN/m) and contact angle (from 140 to 88). With higher amount of nanofluid delivered into the pores through advection and diffusion, over 90% of NAPL droplets were emulsified and their size decreased from 9 to 3 µm. Subsequent nanofluid injection could further remove NAPL from the smaller pores by altering the thickness of NAPL layers adsorbed on the rock. This dynamic solubilization process reached equilibrium after 5 PV of injection, leading to a reduced layer thickness (from 12 to 0.2 µm), a narrower in-situ contact angle distribution around 81, and an additional 16% of NAPL removal.
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