Using Visual Aids to Clarify the Matrix-Fracture Fluid Interaction in Enhanced Unconventional Oil Recovery With Chemical Additives

Summary Matrix-fracture fluid interactions occur during both the fracturing and recovery stages in naturally and hydraulically fractured reservoirs. Understanding the physics and the mechanisms of these interactions (co- or countercurrent manners) is vital for selecting the proper chemicals as fracturing or enhanced oil recovery (EOR) fluid additives. While traditional core experiments often treat the core as a black box, microscopic visualization offers direct observations of key phenomena such as interfacial instability, wettability alteration, and emulsification, particularly in countercurrent imbibition processes. In this study, co- and countercurrent imbibition experiments were visualized using Hele-Shaw cells and glass-etched micromodels. Selected chemicals were tested to evaluate their impact on the imbibition behavior under different boundary conditions and forces. A 17.1 cp crude oil sample was used to saturate these models. To simulate countercurrent imbibition, a Hele-Shaw cell sealed on all sides except the bottom was placed vertically in a transparent container filled with water or chemical solutions. Condition of cocurrent imbibition was developed when two ends of the Hele-Shaw cell were open. Both vertical and horizontal experiments were conducted with two ends being open. In addition, a micromodel was used to conduct oil recovery experiments for further validating the findings from core and Hele-Shaw experiments. Results from Hele-Shaw experiments showed that the absence of chemicals resulted in more fingering due to increased interface instability at a high interfacial tension (IFT). Conversely, the introduction of chemical additives reduced the IFT, promoted wettability alteration toward water-wet, and improved displacement efficiency. The nonionic surfactant Polysorbate 80 and organic alkali ethanolamine (ETA) and high-pH sodium metaborate (NaBO2) demonstrated enhanced imbibition rates and more uniform displacement fronts in countercurrent imbibition, making them promising EOR agents. While the anionic surfactant O342 exhibited a slower oil recovery rate during the initial stages, its ability to alter wettability could contribute to improved final recovery. These findings were consistent with observations from our previous core experiments. Chemical additives also influenced the displacement geometry, producing shorter imbibition lengths but wider swept areas compared with water alone. This enhanced areal displacement efficiency and recovery factors. In horizontal countercurrent experiments, chemical additives shifted flow dynamics toward countercurrent dominance in the absence of gravity effects. Oil recovery experiments conducted in a micromodel further confirmed the effectiveness of chemical additives in suppressing viscous fingering and improving sweep efficiency. In particular, Polysorbate 80 had a higher recovery rate at the early stage, while O342 achieved a higher final recovery. The imbibition front in the O342 experiment was smooth with minimal fingering. Additionally, the presence of Polysorbate 80 led to the formation of emulsions characterized by small oil droplets. The results would be useful for both theoreticians, who develop new mathematical models and simulators to model the imbibition processes, and practitioners who select proper chemicals in field applications.

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