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.