Tight brine-in-oil emulsions, and related high viscosities are common oil field problems experienced in mid- to late-life. Costs for injection equipment (CapEx) and chemical demulsifier (OpEx) are substantial, and poor water separation can result in oil carry over in topside wastewater. Therefore, it is essential to understand the driving forces and conditions of emulsion formation.
Experiments have demonstrated that the asphaltene stability in emulsified oil and in the water-free crude are identical, and that precipitation tendency is independent of water cut. Depressurization experiments showed that although the total amount of precipitate/deposit of the emulsified oil was larger than that of the water-free crude, it contained a lower proportion of asphaltenes in the solids. This suggested that the role of asphaltenes in emulsion formation is smaller than commonly assumed. Indeed, de-asphalted oil formed very tight emulsions that separate out more readily at lower temperatures. Earlier experiments carried out with other low-asphaltene, low-TAN crudes also formed very stable emulsions, implying the potential role of resins in emulsion formation. In this study, the emulsion stability decreased with increasing brine pH, indicating that resins also do not play a major part in the emulsion formation in this crude.
Brine pH changes when the crude is de-gassed and/or when chemicals are added, and production fluid temperatures change from well-bore to topside. Consequently the findings of this study improved our understanding in selection of suitable demulsifiers, the optimization of injection dosage, and identification of the most effective injection point in the system.