Oil production from fractured reservoirs can occur by spontaneous water imbibition and oil expulsion from the matrix into the fracture network. Injection of dilute surfactant can recover additional oil by lowering water-oil interfacial tension (IFT) or altering rock wettability, thereby enhancing countercurrent movement and accelerating gravity segregation. Modeling of such recovery mechanisms requires knowledge of temporal and spatial fluid distribution within porous media. In this study, dilute surfactant imbibition tests performed for vertically oriented carbonate cores of the Yates field were found to produce additional oil over brine imbibition. Computerized tomography (CT) scans were acquired at times during the imbibition process to quantify spatial fluid movement and saturation distribution, and CT results were in reasonable agreement with material balance information. Imbibition and CT-scan results suggest that capillary force and IFT gradient (Marangoni effect) expedited countercurrent movement in the radial direction within a short period, whereas vertical gravity segregation was responsible for a late-time ultimate recovery. Wett ability indices, determined by the U.S. Bureau of Mines centrifuge method, show that dilute surfactants have shifted the wetting characteristic of the Yates rocks toward less oil-wet. A numerical model was developed to simulate the surfactant imbibition experiments. A good agreement between simulated and experimental results was achieved with surfactant diffusion and transitioning of relative permeability and capillary pressure data as a function of IFT and surfactant adsorption. Single and multi-well pilot tests at Yates also demonstrated oil recovery improvement and water-oil-ratio reduction in response to dilute surfactant treatment.
The Yates field, discovered in 1926, is a massive naturally fractured carbonate reservoir located at the southern tip of the Central Basin Platform in the Permian Basin of West Texas. The main production comes from a 400-foot-thick of San Andres formation, which has average matrix porosity and permeability of 15% and 100 md, respectively, and a fracture permeability of greater than 1,000 md. The primary oil recovery mechanism at the Yates field is a gravity-dominated double displacement process in which the gas cap is inflated via nitrogen injection.
Previous viscous flooding experiments using Yates reservoir cores indicated that the injection of dilute surfactants resulted in improved oil recovery (IOR) when compared to injection of brine.1 However, in a fractured reservoir such as Yates, the success of surfactant flooding depends on how effectively the surfactant that resides in the fracture spaces can penetrate the matrix. Thus, static spontaneous imbibition was believed to better represent the fluid exchange between the rock matrix and fracture network. Spontaneous imbibition can be driven either by capillary or gravity forces and is a function of interfacial tension, wett ability, density difference, and characteristic pore radius.