Laboratory monitoring of surfactant imbibition with computerized tomography

Oil production from fractured reservoirs can occur by spontaneous water imb ibition and oil expulsion front the matrix into the fracture network. Injec tion of dilute surfactant can recover additional oil by towering oil/water interfacial tension (IFT) or altering rock wettability, thereby enhancing c ountercurrent movement and accelerating gravity segregation. Modeling of su ch recovery mechanisms requires knowledge of temporal and spatial fluid dis tribution 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 to mography (CT) scans were acquired at times during the imbibition process to quantify spatial fluid movement and saturation distribution, and CT result s were In reasonable agreement with material-balance information. Imbibitio n and CT-scan results suggest that capillary force and IFT gradient (Marang oni effect) expedited countercurrent movement in the radial direction withi n a short period, whereas vertical gravity segregation was responsible for a late-time ultimate recovery. Wettability indices, determined by the U.S. Bureau of Mines (USBM) 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 expe riments. A reasonable agreement between simulated and experimental results was achieved with surfactant diffusion and transitioning df relative permea bility and capillary pressure data as a function of IFT and surfactant adso rption.