Case Studies of Emulsion Behavior at Reservoir Conditions

Abstract

Summary Most emulsion studies are conducted with depressurized crude/water samples. Can emulsions form in the reservoir at high pressures and high temperatures? Generally, the answer to this question is anecdotal. This paper provides a unique method and new data from emulsion studies at high pressures and high temperatures. Two case studies are presented in which emulsions were suspected to be the cause of production challenges in several wells. The experiments were conducted in a special visual pressure/volume/temperature (PVT) cell with the capability of observing emulsion phase behavior at reservoir conditions. The effects of several variables on emulsion behavior were investigated, including shear, pressure, temperature, water cuts, and asphaltene-precipitation tendency of the crude. The first case study is in a field that produces tight emulsions. The results of this study indicate that emulsions can form at reservoir conditions, with mixing, especially if the crude has a tendency to precipitate asphaltenes. The new data suggest that emulsion behavior is linked closely to the presence of fine solids through in-situ dynamic precipitation of organic solids (asphaltenes) and inorganic salts (scales) as well as through fines migration in the reservoir. In the second case study, a series of emulsion tests was performed on bottomhole and wellhead samples from several wells. The results suggest that the emulsions are relatively loose at bottomhole conditions but become progressively tighter with a reduction in pressure and temperature. The tightness of the emulsions was linked to fine solids that stabilize them. These include primarily calcite and sulfur-rich heavy hydrocarbons like asphaltenes, with trace amounts of silicates (clays and/or fine-grained silica), iron-rich precipitates, and barite.