|University of Texas – Austin
|Imbibition; Fractured reservoirs; Surfactant imbibition; Scaling of imbibition
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Natural reservoir drives and waterflooding in naturally fractured carbonate reservoirs with an oil-wet matrix generate very low oil production. Surfactants enhance oil recovery in these reservoirs by altering wettability and reducing interfacial tension (IFT). The main purpose of this research was to determine how to scale up low IFT surfactant imbibition from the lab to fractured, oil-wet carbonate reservoirs. A series of imbibition experiments were conducted using cores with different horizontal (i.e. diameter) and vertical (i.e. height) dimensions. Their fractional oil recoveries (% OOIP) were systematically measured to better understand how to scale up the surfactant imbibition process. There was a particular need to perform experiments using cores with larger horizontal dimensions since almost all previous experiments in the literature used cores with a small diameter, typically 3.8 cm. The core diameters in this study varied from 3.8 to 20 cm. The traditional static imbibition experimental method was adapted and modified by periodically flushing out fluids surrounding the cores inside the cells to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. The high performance surfactant formulations for the oils used on in this study were developed using microemulsion phase behavior tests. These surfactants gave ultra-low IFT (on the order of 0.001 dynes/cm) at optimal salinity and good aqueous stability. Although most of the experiments used ultra-low IFT formulations, experiments using higher IFT (on the order of 0.1 dynes/cm) formulations were also performed for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. In addition, experiments were done to understand the role of other variables on oil recovery, such as matrix permeability, surfactant and co-solvent concentrations, microemulsion viscosity, and oil viscosity. A simple analytical model was developed to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock and fluid properties, and time. The model and experimental data are in good agreement considering the many simplifications made to derive the model. Both experimental data and the model showed that the oil recovery was lower for cores with larger horizontal and vertical dimensions. However, the decrease was not proportional to an increase in these dimensions. The scaling implied by the model is significantly different than the traditional scaling groups in the literature. Advisors/Committee Members: Pope, G. A. (advisor), Mohanty, Kishore K (committee member).