Some surface-active chemicals are able to improve the spontaneous imbibition of water into oil-wet carbonates. In this work, the oil recovery from oil-wet reservoir cores was compared using aqueous solutions of an ethoxylated alcohol (EA) and a cationic surfactant (C12TAB). The experiments were conducted at room temperature using short (∼5 cm) and long (∼30 cm) cores with initial water saturation in the range of 17-33%. Due to wide variation in porous structure, the cores were characterized into two groups, i.e., moldic and sucrosic. The former cores had more than 25% of the pore volume (PV) related to vugs, and the latter appeared more homogeneous. The permeability of the moldic and sucrosic cores varied between 20 and 180 and 80-350 mD, respectively. In general, the efficiency of C12TAB was superior to EA regarding spontaneous oil expulsion from the cores. For the short core experiments, about 40-45% of original oil in place (OOIP) was recovered using C12TAB, while only 10% was the average recovery using EA. The available data for the short cores gave no reasons to discriminate between moldic and sucrosic cores regarding oil expulsion. The long 162 mD sucrosic core expelled 65% of OOIP in the presence of C12TAB. The high oil recovery, compared to the short cores, was related to greater impact of gravity forces. The imbibition of EA solution into the long 45 mD core was very small, less than 5%, but large improvements were achieved when changing to C12TAB solution. Contact angle measurements on oil-wet calcite crystals confirmed that C12TAB was much more effective than EA in altering wettability toward more water-wet conditions.

Summary 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 oil/water 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. 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 experiments. A reasonable 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. Introduction 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-ft-thick San Andres formation with 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 through nitrogen injection. Dilute surfactant pilot tests have been conducted at the Yates field since early 1990. The surfactant, Shell 91-8 nonionic ethoxy alcohol, was diluted with produced water to a concentration (3,100-3,880 ppm) much higher than the critical micelle concentration (CMC) and was injected into the oil/water transition zone below the oil/water contact (OWC) for both single-and multiwell tests. Single- and multiwell pilot tests demonstrated improved oil recovery (IOR) and a reduced water/oil ratio in response to dilute surfactant treatments. Previous viscous flooding experiments with Yates reservoir cores indicated that the injection of dilute surfactants resulted in improved oil recovery when compared to the injection of brine.1 However, in a fractured reservoir such as Yates, the success of surfactant flooding depends on how effectively the surfactant residing in the fracture spaces can penetrate the matrix. Thus, static sponta neous imbibition was believed to better represent the fluid exchange between the rock matrix and fracture network. Spontaneous imbibition can be driven by either capillary or gravity forces and is a function of interfacial tension, wettability, density difference, and characteristic pore radius. Austad et al. investigated spontaneous surfactant imbibition into oil-saturated and low-permeability (less than 10 md) chalk cores.2–4 They concluded that, for water- and mixed-wet cores using an anionic surfactant, the early-time recovery mechanism was countercurrent movement, followed by gravity displacement at late time. For oil-wet cores using a cationic surfactant, the primary displacement mechanism was countercurrent movement. Countercurrent movement was believed to be a function not only of capillary forces, but also of the Marangoni effect that describes spontaneous interfacial flows induced by an IFT gradient.3,5,6 It was believed that the Marangoni effect created a hydrodynamic shear stress at the oil/water interface that provided additional force to mobilize the displaced oil phase in the direction opposite to the imbibed aqueous phase. For the oil-wet cores, Austad et al. hypothesized that the cationic surfactant improved oil recovery by altering rock wettability.4 In particular, the increased water wettability resulted in a decreased contact angle and increased capillary forces, thus maximizing countercurrent movement. The Yates reservoir is similarly believed to be oil- to mixed-wet. Cationic surfactants, although effective in altering wettability for oil-wet rocks, are too expensive to be implemented in a field treatment. Nonionic and anionic ethoxylated surfactants were selected for the Yates field pilot tests and laboratory studies because they were less expensive than cationic surfactants and they improved oil recovery without forming emulsions. The IOR mechanism for the ethoxylated surfactants used at Yates is different from the mechanism for the cationic surfactants used by Austad et al. The different IOR mechanism at Yates is largely owing to the nature of the highly fractured reservoir with a high-permeability matrix (average 100 md). Gravity is the dominant force in oil recovery for a fractured reservoir (mixed dolomite/sandstone formation).7 For such a gravity-dominated process, oil is displaced from the matrix blocks by cocurrent movement vertically through the top surface. The ethoxylated surfactants used at Yates are believed to quickly distribute monomers along the oil/water interface. These monomers lower the IFT and, while the surfactant is present in the aqueous phase, they may alter the wettability from oil-wet to less oil-wet. Thus, although the wettability alteration may occur, enhancing gravity forces owing to IFT-lowering may be the primary IOR mechanism for the Yates field. The objective of this work is to quantify the relative significance of radial countercurrent movement caused by capillary forces and vertical cocurrent movement caused by gravity during surfactant static imbibition into Yates cores. The importance of IOR mechanisms such as adsorption-dependent wettability alteration, interfacial tension reduction, and surfactant diffusion are illustrated through a comparison of laboratory data and numerical simulation results.

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. Introduction 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.

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