Spontaneous Imbibition and Core Flooding Experiments of Enhanced Oil Recovery in Tight Reservoirs with Surfactants

Despite the implementation of hydraulic fracturing technologies, the oil recovery in tight oil reservoirs is still poor. In this study, cationic, anionic, and nonionic surfactants of various sorts were investigated to improve oil recovery in tight carbonate cores from the Middle Bakken Formation in the Williston Basin. Petrophysical investigations were performed on the samples prior to the imbibition and core-flooding experiments. The composition of the minerals was examined using the XRD technique. To investigate the pore-size distribution and microstructures, nitrogen adsorption and SEM techniques were applied. The next step involved brine and surfactant imbibition for six Bakken cores and two Berea sandstone cores. The core samples were completely saturated with Bakken crude oil prior to the experiments. The core plugs were then submerged into the brine and surfactant solutions. The volume of recovered oil was measured using imbibition cells as part of experiments involving brine and surfactant ingestion into oil-filled cores. According to the findings, oil recovery from brine imbibition ranges from 4.3% to 15%, whereas oil recovery from surfactant imbibition can range from 9% to 28%. According to the findings, core samples with more clay and larger pore diameters produce higher levels of oil recovery. Additionally, two tight Bakken core samples were used in core-flooding tests. Brine and a separate surfactant solution were the injected fluids. The primary oil recovery from brine flooding on core samples is between 23% and 25%, according to the results. The maximum oil recovery by second-stage surfactant flooding is approximately 33% and 35%. The anionic surfactants appear to yield a better oil recovery in tight Bakken rocks, possibly due to their higher carbonate mineral concentrations, especially clays, according to both the core-scale imbibition and flooding experiments. For studied samples with larger pore sizes, the oil recovery is higher. The knowledge of the impacts of mineral composition, pore size, and surfactant types on oil recovery in tight carbonate rocks is improved by this study.

Automated summary

This study investigates the use of different types of cationic, anionic, and nonionic surfactants to improve oil recovery in tight carbonate cores from the Middle Bakken Formation in the Williston Basin. The findings suggest that core samples with more clay and larger pore diameters exhibit higher oil recovery. Anionic surfactants appear to yield better oil recovery in tight Bakken rocks, possibly due to their higher carbonate mineral concentrations. This study enhances our understanding of the impacts of mineral composition, pore size, and surfactant types on oil recovery in tight carbonate rocks.