The hydraulic fracturing technique remains essential to unlock fossil fuel from shale oil reservoirs. However, water imbibed by shale during hydraulic fracturing triggers environmental and technical challenges due to the low flowback water recovery. While it appears that the imbibition of fracturing fluid is a complex function of physico-chemical processes in particular capillary force which is associated with wettability of oil-brine-shale, the controlling factor(s) to govern the wettability is incomplete and the literature data in this context is missing. We thus measured the adsorption/desorption of asphaltenes on silica surface in the presence of brines using quartz crystal microbalance with dissipation (QCM-D). We detected zeta potential of asphaltene-brine and brine-silica systems and calculated the disjoining pressures of the asphaltene-brine-silica system in the case of different salinity. Moreover, we performed a geochemical study to quantify the variation of surface chemical species at asphaltene and silica surfaces with different pH values and used the chemical force microscope (CFM) method to quantify the effect of pH on intermolecular forces. Our results show that lowering salinity or raising pH reduced the adhesion force between asphaltene and silica surface. For example, at a pH value of 6.5, when the concentration of injected water is reduced from 1000 mM to 100 mM and 10 mM, the adhesion force decreased by approximately 58% and 66%, respectively. In addition, for the 100 mM NaCl solution, when the pH value increased from 4.5 to 6.5 and 9, the adhesion force decreased by approximately 56% and 87%, respectively. Decreased adhesion forces between asphaltene and the silica surface could promote the desorption of asphaltene from the silica surface, resulting in a negative zeta potential for both asphaltene-silica and brine-silica interfaces and a shift of wettability towards water-wet characteristic. During such a process, -NH⁺ number at asphaltene surfaces decreases and the bonds between -NH⁺ and >SiO⁻ break down, to further interpret the formation of a thinner asphaltene adlayer on the rock surface. This study proposes a reliable theoretical basis for the application of hydraulic fracturing technology, and a facile and possible manipulation strategy to increase flowback water from unconventional reservoirs.

Benzoxazines are a kind of high-performance thermosetting resin that can undergo ring-opening polymerization to generate cross-linking structures. Here, two benzoxazine monomers, bisphenol A/aniline type (BA-a) and bisphenol A/tert-butylamine type (BA-tb), were synthesized and mixed with three tertiary amine catalysts like 2-methylimidazole (2MI), 1,2-dimethylimidazole (12MI), 4-dimethylaminopyridine (DMAP). Differential scanning calorimetry (DSC) was performed to study the curing behaviors and the curing kinetics of two benzoxazine/catalyst systems. The results indicated that all amines had a catalytic effect on the polymerization of both benzoxazines, and the BA-a/catalyst systems showed relatively higher activity. In addition, Fourier transform infrared (FTIR) and nuclear magnetic resonance (NMR) spectra were procured to analyze structural changes in the benzoxazine/catalyst systems during the curing process. The presence of the catalysts promoted the progress of the ring-opening reactions and the formation of the phenolic units in the cross-linking structures, and these evolutions were more obvious for the BA-a/catalyst system than the BA-tb/catalyst system. Furthermore, a thermogravimetric analysis (TGA) was conducted to analyze the thermal stability of the cured systems. Finally, possible curing reaction mechanisms were proposed for these benzoxazine/amine systems.

In order to improve the adaptability of low-salinity waterflooding technology in some areas where freshwater resources are scarce, we aimed at implementing the low-salinity effect (LSE) in carbonate reservoirs through tuning injection seawater composition. LSE of ion tuning water (ITW) was verified by the results of core flooding tests, obtaining a water-free recovery factor of 50.7% and cumulative oil recovery of 77.2%. The micro mechanisms behind it were revealed via direct force-measuring and Zeta parameter (Zeta_p) measuring. Our results are expected to provide a new LSW strategy via tuning injection seawater composition in the case of carbonate reservoirs.