Alteration of Interfacial Properties by Chemicals and Nanomaterials To Improve Heavy Oil Recovery at Elevated Temperatures

Abstract

Heavy oil containing carbonate and sand reservoirs exhibits reverse wettability characteristics. Dependent upon the temperature, phase of injected steam, and rock type, the wettability may be altered to more water-wet. The addition of chemicals to hot water (or steam) may further change the interfacial properties (more water-wet and less interfacial tension). Surfactants were tested extensively for this process in the past, and their temperature resistance was an obstacle. New-generation chemicals need further investigation from a technically and economically success point of view. The objective was to investigate the alteration of interfacial properties induced by different types of chemical agents under high-temperature conditions. To achieve this, four experimental tools (contact angle measurement, interfacial tension measurement, atomic force microscopy, and spontaneous imbibition tests) were applied. High-pressure and high-temperature contact angle measurements enabled a quick method to identify the suitability of the chemicals for wettability modification. Interfacial tension between oil and different chemical solutions was measured with a variation of the temperature. In the imbibition tests, core samples were exposed to heating for longer time periods, so that the temperature resistance of the chemicals was also tested. Imbibition experiments were conducted at ambient pressure and 90 °C. The combination of the contact angle and interfacial tension provided insight into the recovery enhancement mechanisms. Six different chemicals, including an ionic liquid, three nanofluids (silica, aluminum, and zirconium oxides), a cationic surfactant, and a high-pH solution, were chosen based on our screening study. Heavy oil used was obtained from a field in Alberta (6000 cP). Contact angles were measured on mica, calcite, sandstone, and limestone plates. The experimental temperature ranged from 25 to 200 °C, and the pressure was changed to keep the solution in the aqueous phase. Promising modifiers for different rock types under different temperatures were screened separately. Visual data illustrating the deposition of the chemicals on the surface of mica and well-polished calcite substrates and removal of the existing oil layer after the treatment with different chemicals were obtained by atomic force microscopy. Finally, spontaneous imbibition tests were performed on sandstone and limestone cores with screened promising modifiers. Oil recovery in this phase was continuously monitored to evaluate wettability alteration capability, and the mechanism(s) involved were analyzed for different chemicals. Analysis of wettability alteration mechanisms and interfacial tension reduction capabilities is expected to be useful in the selection of suitable and temperature-resistant chemicals for high-temperature applications in different reservoir rocks.