Chemical enhanced oil recovery application in a high-temperature, high-salinity carbonate reservoir




Abalkhail, Nassir

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Research and field applications of chemical enhanced oil recovery (CEOR) have been in increasing demand due to declining production from primary and secondary recovery methods in mature oil fields, attractive oil and chemicals prices, and the ever-increasing demand for energy. The main goal of using surfactants is to reduce the IFT between the oil and water, which enables the mobilization of residual oil. High molecular weight water-soluble polymers are added to the surfactant solution to increase its viscosity, which enables the formation and displacement of a clean oil bank, and also to mitigate reservoir heterogeneity and improve sweep efficiency. Advancements in CEOR technology have enabled the efficient use of surfactants and polymers in high-temperature and high-salinity reservoirs, especially sandstone reservoirs, but carbonate reservoirs have been more challenging. A giant carbonate reservoir at 100°C was the target for this research. A chemical formulation was developed to achieve ultra-low interfacial tension (IFT) using a mixture of carboxylate surfactant, internal olefin sulfonates (IOS) co-surfactants, and co-solvent. The performance of chemical formulations was systematically and thoroughly tested with different types of alkalis and without alkali. Using the optimum parameters, the best formulations were then tested using outcrop limestone cores and a carbonate reservoir core. Furthermore, a hydrolyzed polyacrylamide polymer at 100°C was tested and its thermal stability improved by optimizing the polymer preparation procedures. Ammonia and sodium hydroxide as well as Diisopropylamine (DIPA) with ethylene oxide added to it were used to increase the pH and promote low surfactant retention. Both high oil recovery and nearly zero surfactant retention were achieved in the outcrop limestone cores. The carbonate reservoir core consisted of a high fraction of dolomite. Novel tests of the alkalis were done using a reservoir core plug to determine the pH after ageing the core for several days. Based on these tests, ammonia and DIPA-10EO were used in the chemical solution injected into the reservoir core. The final oil saturation was nearly zero and the retention was only 0.083 mg/g-rock. This is an extremely low surfactant retention, especially for a carbonate core. Such low retention is very favorable for the economics of ASP flooding of the target reservoir.


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