Hypothesis: As a mainstream process in the extraction and recovery of crude oil, water is injected into reservoirs in the so-called waterflooding process to facilitate the oil displacement through the wellbore, typically generating water-in-oil (W/O) emulsions. Based on economic considerations, sea water is used in the flooding process; however, the ionic incompatibility between the injected water and the formation water inside the reservoir may precipitate sparingly-soluble inorganic salts (scale). We hypothesize that calcium carbonate (CaCO3) scale dynamically interacts with cationic surfactants in W/O emulsions, resulting in (i) scale growth retardation and (ii) emulsion destabilization. Experiments: We developed stable W/O emulsions via combining droplet-based microfluidics with multifactorial optimizations to investigate the influence of emulsion properties, such as surfactant type and concentrations, temperature, and pH, as well as calcium ions on the CaCO3 scaling kinetics and emulsion stability. The CaCO3 scale was characterized based on particle size and charge, lattice structure, interactions with the surfactant, and time-dependent effects on emulsion stability. Findings: The interfacial interactions between the cationic surfactant (cetyltrimethylammonium bromide, CTAB) and CaCO3 retarded scale growth rate, decreased crystal size, and destabilized emulsion within hours as a result of surfactant depletion at the water–oil interface. The surfactant did not affect the crystal structure of scale, which was formed as the most thermodynamically stable crystalline polymorph, calcite, at the ambient condition. This fundamental study may open new opportunities for engineering stable W/O emulsions, e.g., for enhanced oil recovery (EOR), and developing scale-resistant multiphase flows.
All Science Journal Classification (ASJC) codes
- Electronic, Optical and Magnetic Materials
- Surfaces, Coatings and Films
- Colloid and Surface Chemistry