Influence of inorganic scale formation on asphaltene behavior during water injection

This study presents significant advances in understanding the complex interplay between inorganic scaling and asphaltene behavior in oil–water systems through innovative experimental and analytical approaches. We aim to elucidate non-linear, concentration-dependent scaling phenomena, molecular-level asphaltene transformations during scaling, and the coupled impacts on interfacial properties. To that end, we conducted carefully designed static incompatibility tests using formation waters (FWs) containing Ba2+ or Sr2+ and modified seawater (SW) with controlled sulfate (4 × Na2SO4), quantified precipitates and characterized them by energy dispersive X-ray spectroscopy (EDS)/X-ray diffraction (XRD), tracked molecular signatures by Fourier transform infrared spectroscopy (FTIR), and monitored polarity indices and interfacial tension (IFT). The results show that sulfate concentration thresholds govern scaling; at 4 × Na2SO4, Sr2+ systems yield 85.43% gypsum with 14.57% halite, whereas Ba2+ systems form 75.08% gypsum and 24.92% barite, confirming barium’s stronger scaling tendency. Polarity indices shift from 0.1296 (crude oil) to 0.1515 (a non-scaling Sr2+ condition) and then decrease to 0.1388 under scaling, with more pronounced effects in Ba2+ systems; EDS indicates sequestration of oxygen and sulfur heteroatoms within scale matrices. Consistently, IFT rises from 27.33 to 39.04 mN/m in Sr2+ systems and from 33.41 to 42.73 mN/m in Ba2+ systems under scaling. These findings provide a quantitative framework for predicting and managing coupled scaling–asphaltene interactions in carbonate reservoirs and enable optimized water-injection strategies that jointly control scale formation and enhance oil recovery, improving on conventional approaches that treat these challenges separately.