Low-salinity water flooding (LSWF) for hydrocarbon recovery has attracted industrial attention, owing to its simplicity and economic feasibility. Although this topic has received numerous studies, mechanisms driving the low-salinity effect remain poorly understood. This study is aimed at investigating the direct effects of injecting lowsalinity brine (0.6 and 0.2 M NaCl) as the non-wetting fluid and Soltrol 130 as a synthetic wetting fluid on outcrop "Austin Chalk" rock samples. The petrophysical properties of rock samples were estimated by saturating the core samples with high-and low-salinity brine at laboratory conditions. Experiments were conducted for unsteady-state and steady-state flow for both imbibition and drainage processes. A shift to the right has been observed for the relative permeability curve of 0.2 M NaCl along with a drop in irreducible water saturation (S wi ) and in residual oil saturation (S or ). Furthermore, the results have shown a reduction in irreducible water saturation from 22.2 to 18.7% when using 0.2 M NaCl compared to 0.6 M NaCl. The current research demonstrates that ionic interactions among rock, oil, and brine compositions would alter the in situ wettability of the carbonate samples from oil-wet/mixed-wet to more water-wet conditions. A correlation is found among the double-layer expansion, ζ potential, and wettability alteration during LSWF. Moreover, improved oil recovery takes place during LSWF only when a repulsive electrostatic force between oil−brine and mineral−brine interfaces is induced by the change in brine composition. ζ potential of the carbonate is found to become more negative with the dilution of the brine. After the sample is aged with oil, the ζ potential changed, indicating an alteration in wettability.
Despite rock surface charge being a critical component in predicting the reservoir behavior, the subsurface characteristics are still poorly understood, specially, those of sandstones, which are of key economic importance in the oil and gas industry. Even though a rock surface is originally considered to be neutrally charged, surface charges are created in the presence of water and dissolved ions. Moreover, a major proportion of sandstone reservoirs are composed of silica which creates surface charges through dissociation of silanols in the presence of water and/or acids. Rock subsurface chemistry is a primary factor that determines the variability of several key reservoir parameters (e.g., capillary pressures or residual saturations). Nuclear magnetic resonance (NMR) is a well-established tool with which such rock surface chemistry can be measured in situ. For example, surface charge is a vital characteristic with which single-phase and multiphase fluid flow behavior can be predicted (e.g., it determines colloidal stabilities or streaming potentials); the surface charge/surface potential is thus highly significant for a wide range of applications and processes, for example, enhanced oil/gas recovery, hydrogen/CO 2 geo-storage, or contaminant transport. This study provides novel insights into fundamental rock surface chemistry and how this is influenced by the acidity of the aqueous phase in the subsurface. Specifically, we systematically examined sandstone surface chemistry as a function of mineral acid concentration via NMR T 2 response measurements. For this, Bentheimer sandstone samples were treated with aqueous hydrochloric acid solutions of different concentrations, and NMR T 2 distribution measurements were performed for the initial and treated samples. The results indicated that higher concentrations of hydrochloric acid (and thus more surface protonation) yielded much shorter T 2 relaxation times compared to lower concentrations. This work thus provides fundamental information about in situ sandstone surface chemistry and therefore aids in the basic understanding and implementation of key geologic questions and engineering projects.
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