Modeling Wettability Alteration By Surfactants in Naturally Fractured Reservoirs
- Mojdeh Delshad (University of Texas at Austin) | Nariman Fathi Najafabadi (University of Texas at Austin) | Glen Anderson (University of Texas at Austin) | Gary A. Pope (University of Texas at Austin) | Kamy Sepehrnoori (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2009
- Document Type
- Journal Paper
- 361 - 370
- 2009. Society of Petroleum Engineers
- 6 in the last 30 days
- 3,893 since 2007
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Laboratory surfactant and hot-water floods have shown a great potential in increasing oil recovery for reservoirs that are naturally fractured and have low-permeability, mixed-wet matrix rocks. Fractured, mixed-wet formations usually have poor waterflood performance because the injected water tends to flow in the fractures and imbibition into the matrix is not very significant. Surfactants have been used to change the wettability for increasing the oil recovery by increased imbibition of the water into the rock matrix. The mechanisms for oil recovery are combined effects of reduced interfacial tension (IFT), reduced mobility ratio, and wettability alteration. The goal of this research is to adapt an existing numerical reservoir simulator to model chemical processes leading to wettability alteration in naturally fractured reservoirs. Surfactants have been used to change the wettability, with the goal of increasing the oil recovery by increased imbibition of the water into the rock matrix. Reservoir simulation is required to scale up the process from laboratory to field conditions, as well as to understand and interpret reservoir data. A chemical-flooding simulator is adapted to model improved-oil-recovery processes involving wettability alteration using surfactants. Multiple relative permeability and capillary pressure curves corresponding to different wetting states are used to model the wettability alteration. Simulations are performed to better understand and predict enhanced oil recovery as a function of wettability alteration, and to investigate the impact of uncertainties in the fracture and matrix properties, reservoir heterogeneity, matrix diffusion, buoyancy-driven flow, initial water saturation, and formation wettability. The proposed wettability-alteration model and its implementation were successfully validated against laboratory experiments. Upscaled simulations indicated the importance of matrix properties on the rate of imbibition. The oil recovery increases with an increase in matrix permeability and a decrease in matrix initial water saturation.
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