Wetting and alteration of wetting are among the most important material properties of fluid−fluid−substrate systems in biological and industrial systems. An important industrial application of wetting and wetting alteration is related to displacement of crude oil by water injection in porous media. Water injection in oil reservoirs has been used since the early periods of oil production. Recently, it has been discovered that the salt concentration in the injected water may have a significant effect on the oil recovery. The process is under active research for the need of an improved understanding. In this work, we investigate the governing elements of surface wettability with two different crude oils on two atomistically smooth surfaces (mica and quartz) and one smooth surface (calcite) as a function of the salt concentration (0−3 M) and type (mono-versus divalent). We investigate the change of wettability from NaCl and MgCl 2 salts over a wide concentration for the first time. The measurements are based on long enough aging times and droplet sizes that give equilibrium and size-independent contact angles. Our measurements show a non-monotonic behavior, in that, as NaCl concentration increases, there is a decrease (increase of water-wetting) and then an increase (decrease of water-wetting) of the contact angle in all of the systems that we have studied. MgCl 2 salt shows two trends with an increasing concentration. For mica and quartz, there is first a decrease of the contact angle and then an increase followed by a second sharp decrease at high MgCl 2 concentrations. For calcite substrate, we observe an increase of the contact angle reaching a maximum and then a decrease with an increasing salt concentration. These observations have profound implications on the effect of salts on wettability alteration. The measurements have set the stage for atomistic simulations for a molecular understanding of the salt effect in complex fluids.

We report results from a systematic investigation of the effect of the temperature on the wettability of oil/brine/rock systems. An oil sample, produced from a sandstone reservoir, was tested on sandstone-like substrates (i.e., mica and quartz) in NaCl and MgCl2 solutions with concentrations ranging from 0 to 3 M. Raising the temperature from 25 to 50 °C has no discernible effect on the contact angle, regardless of substrate type, brine type, or salt concentration. Another oil sample, obtained from a carbonate reservoir, was examined on carbonate-like substrates (i.e., calcite) in NaCl and MgCl2 solutions over a concentration range of 0–1 M. The contact angles decrease as the temperature increases from 25 to 65 °C, and this temperature effect also strongly depends upon the brine type and salt concentration. A systematic examination of the ζ potential of rock/brine and oil/brine interfaces under different conditions and subsequent discussions indicate that contact angle and ζ potential may not be directly linked. These findings regarding the wettability of oil/brine/rock systems may improve the understanding of low-salinity wateflooding mechanisms by elucidating the combined effects of the temperature and other critical variables, including brine type, brine concentration, crude oil composition, and substrate type.

Summary Laboratory surfactant and hot-water floods have shown a great potential in increasing oil recovery for reservoirs that are naturally fractured and have low-permeability, mixed-wet matrix rocks. Fractured, mixed-wet formations usually have poor waterflood performance because the injected water tends to flow in the fractures and imbibition into the matrix is not very significant. Surfactants have been used to change the wettability for increasing the oil recovery by increased imbibition of the water into the rock matrix. The mechanisms for oil recovery are combined effects of reduced interfacial tension (IFT), reduced mobility ratio, and wettability alteration. The goal of this research is to adapt an existing numerical reservoir simulator to model chemical processes leading to wettability alteration in naturally fractured reservoirs. Surfactants have been used to change the wettability, with the goal of increasing the oil recovery by increased imbibition of the water into the rock matrix. Reservoir simulation is required to scale up the process from laboratory to field conditions, as well as to understand and interpret reservoir data. A chemical-flooding simulator is adapted to model improved-oil-recovery processes involving wettability alteration using surfactants. Multiple relative permeability and capillary pressure curves corresponding to different wetting states are used to model the wettability alteration. Simulations are performed to better understand and predict enhanced oil recovery as a function of wettability alteration, and to investigate the impact of uncertainties in the fracture and matrix properties, reservoir heterogeneity, matrix diffusion, buoyancy-driven flow, initial water saturation, and formation wettability. The proposed wettability-alteration model and its implementation were successfully validated against laboratory experiments. Upscaled simulations indicated the importance of matrix properties on the rate of imbibition. The oil recovery increases with an increase in matrix permeability and a decrease in matrix initial water saturation.

High-concentration brines generally cause the wettability of petroleum fluid–brine–rock systems to become less water-wet (more oil-wet). The addition of alcohols to the brine, however, may produce an opposite effect. In this work, we investigate the synergic effects of a low concentration of 1-pentanol and brines on the wettability of petroleum fluid–brine–rock systems. The variables examined include the mineral type (mica, quartz, calcite), brine concentration (0–3 M), ion type (monovalent and divalent), crude oil (samples from sandstone and carbonate reservoirs), and 1-pentanol concentration (0.5 and 1 wt %). Adding 1 wt % 1-pentanol to the brine only slightly affects the wettability of a petroleum fluid on sandstone-like mineral surfaces (mica and quartz), whereas the effect is significant for carbonate-like mineral surfaces (calcite). A maximum reduction of 80° in contact angle (measured through the brine phase) is observed at 0.1 M NaCl and 0.5 wt % 1-pentanol. ζ-Potentials of both brine–petroleum fluid and brine–rock interfaces are found to be insensitive to the presence of 1-pentanol in the brine. Based on these observations, we propose that the accumulation of 1-pentanol in the thin brine film confined between the petroleum fluid and the rock surface results in a significant change of the wettability. Our finding may have various practical applications, one of which is the use of a low concentration of 1-pentanol for improving oil production.

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