Chemical incompatibility between formation and injection water: implications for oil recovery in porous media

Low-salinity water flooding is widely recognized as an effective enhanced oil recovery (EOR) method, primarily by altering wettability and reducing interfacial tension. However, chemical incompatibility between injected water and formation water may induce scale deposition, leading to pore blockage and injectivity impairment, thereby posing significant challenges to EOR efficiency. A better understanding of the interplay between chemical incompatibility and pore-scale oil-water interface dynamics is crucial for optimizing waterflooding performance, particularly in low-permeability reservoirs. This study integrates ion characterization, colloidal analysis, solubility product calculations, and microfluidic visualization to systematically evaluate the compatibility of formation and injected waters, while directly observing pore-scale fluid displacement processes. Results reveal that ionic composition analysis reveals significant incompatibility between the sulfate-rich injection water and calcium/barium-containing formation water, creating conditions favorable for mineral scaling. Subsequent examination of scaling dynamics demonstrates that incompatible fluid mixing initiates nanoparticle formation, which progresses through two distinct growth pathways: coalescence-driven crystal enlargement and aggregation-dominated cluster formation, ultimately leading to pore-throat obstruction. Microfluidic visualization shows residual oil persists primarily as interfacial films and pore-center clusters after initial waterflooding, with their spatial arrangement governed by salinity-dependent wettability alteration and capillary forces. The introduction of incompatible water further exacerbates fluid trapping through capillary valve effects-a capillary-driven resistance occurring when interfacial forces oppose fluid advancement at pore-throat junctions-creating stagnant zones that promote particle accumulation. Pressure monitoring during flooding experiments reveals characteristic response patterns: an initial pressure peak during waterflooding, followed by secondary pressure elevation due to scale deposition, and subsequent partial pressure reduction through surfactant-mediated interfacial tension reduction and wettability modification. A self-reinforcing cycle emerges, coupling ion incompatibility, capillary trapping, and precipitate growth, encapsulated in a colloid-capillary coupling framework. To disrupt this cycle, a synergistic chemical strategy combining surfactants and scale inhibitors is proposed, simultaneously enabling interface modification and nucleation suppression to enhance sweep efficiency. This integrated approach provides a mechanistic foundation for optimizing waterflooding in chemically complex reservoirs, achieving a balanced synergy between interfacial control and scale mitigation.