The combination of chemical enhanced oil recovery (CEOR) and low salinity water (LSW) flooding is one of the most attractive enhanced oil recovery (EOR) methods. While several studies on CEOR have been performed to date, there still exists a lack of mechanistic understanding on the synergism between surfactant, alkali and LSW. This synergism, in terms of fluid–fluid interactions, is experimentally investigated in this study, and mechanistic understanding is gained through fluid analysis techniques. Two surfactants, one cationic and one anionic, namely an alkyltrimethylammonium bromide (C19TAB) and sodium dodecylbenzenesulfonate (SDBS), were tested, together with NaOH used as the alkali, diluted formation brine used as the LSW, and the crude oil was collected from an Iranian carbonate oil reservoir. Fluids were analyzed using pendant drop method for interfacial tension (IFT) measurement, and Fourier transform infrared spectroscopy for determination of aqueous and oleic phase chemical interaction. The optimum concentration of LSW for IFT reduction was investigated to be 1000 ppm. Additionally, both surfactants reduced IFT significantly, from 28.86 mN/m to well below 0.80 mN/m, but in the presence of optimal alkali concentration the IFT dropped further to below 0.30 mN/m. IFT reduction by alkali was linked to the production of three different types of in situ anionic surfactants, while in the case of anionic and cationic surfactants, saponification reactions and the formation of the C19TAOH alcohol, respectively, were linked to IFT reduction. The critical micelle concentration and optimal alkali concentration when using cationic C19TAB were significantly lower than with the anionic surfactant; respectively: 335 vs 5000 ppm, and 500 vs 5000 ppm. However, it was found that SDBS was more compatible with NaOH than C19TAB, due to occurrence of alkali deposition with the latter beyond the optimal point.

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Although alkaline-surfactant-polymer (ASP) flooding has proven efficient for heavy oil recovery, the displacement mechanisms and efficiency of this process should be discussed further in fractured porous media. In this study, several ASP flooding tests were conducted in fractured glass-etched micromodels with a typical waterflood geometrical configuration, i.e. five-spot injection-production pattern. The ASP flooding tests were conducted at constant injection flow rates but different fracture geometrical characteristics. The ASP solutions consisted of five polymers, two surfactants, and three alkaline types. It was found that using synthetic polymers, especially hydrolyzed polyacrylamide with high molecular mass, as well as cationic surfactant increases the ultimate recovery. The location of the injection well with respect to the fracture system plays a significant role in the ASP flooding performance, i.e. an increase in the angle associated with the longitudinal extension of fractures with respect to the main flow direction resulted in enhanced oil recovery and also postponed the wetting phase breakthrough time. Mechanistic study of this displacement process revealed that dispersive and diffusive behaviour of the ASP front enhanced the fluid transport from fracture to matrix and increased the microscopic displacement efficiency. Emulsification and coalescence mechanisms were responsible for ASP frontal advancement. Residual oil in the invaded region, which was observed in the form of discontinuous oil ganglia dispersed in the invaded pore bodies or in the form of pendular bridges formed around some of the solid particles, was mobilized in the form of oil wads through the droplets of the displacing phase.

The influence of far-field stresses on fracture apertures in a fragmented rock layer is investigated using finite element analysis of a three-dimensional mechanical model. The model implements realistic boundary conditions, interactions between the fragmented layer and neighboring plastic rock layers, and frictional interfaces between the rock blocks. Stress-strain analysis is conducted to obtain stress variations within the fragmented rock layer and the block displacements and rotations. The fracture apertures are calculated using the local stress states instead of the far-field stresses simply being projected on the fractures. It is observed that fracture apertures can vary for the fracture segments over the individual blocks. Ensemble permeability is calculated by running a single-phase flow analysis considering the obtained fracture apertures for fracture segments. The influence of the rock block displacements, rotations and deformations, difference between the mechanical properties of the rock layers, and the orientation of the horizontal stresses is investigated on the ensemble permeability. It is demonstrated that the compressibility of the neighboring layers and block rotations and deformations have significant influence on the permeability of the fragmented rock layer. These effects, which may be ignored in simpler aperture calculation models, can result in considerable inaccuracies in the estimation of fracture apertures and ensemble permeability. Hence, such methods may only be used as indicative tools.

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