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

Abstract Matrix-fracture fluid interactions occur during both the fracturing and recovery stages in naturally and hydraulically fractured oil and gas reservoirs. Understanding the physics and the mechanisms of these interactions (co- or counter-current manners) is vital for selecting the proper chemicals as fracturing or 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 counter-current imbibition processes. In this study, co- and counter-current imbibition experiments were visualized using Hele-Shaw cells and glass etched micromodels. Selected chemicals were tested to evaluate their impact on the imbibition behaviour under different boundary conditions and forces. A 17.1 cP crude oil sample and air were used to saturate these models to mimic oil and gas reservoirs, respectively. To simulate counter-current 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 co-current 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 the gas recovery experiments using a micromodel, its one side was in contact with water or a chemical solution while the opposite side was open for outflow. In addition, another micromodel was employed to conduct oil recovery experiments for further validating the findings from core and Hele-Shaw experiments. Results revealed that the absence of chemicals resulted in more finger channels due to increased interface instability at high interfacial tension (IFT). Conversely, the introduction of chemical additives reduced IFT, promoted wettability alteration toward water-wet conditions, and improved displacement efficiency. The nonionic surfactant Tween 80, and organic alkali ethanolamine (ETA) and high-pH sodium metaborate (NaBO2) demonstrated enhanced imbibition rates and more uniform displacement fronts in counter-current 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 are consistent with observations from our previous core experiments. Chemical additives also influenced the displacement geometry, producing shorter imbibition lengths but wider swept areas compared to water alone. This enhanced areal displacement efficiency and recovery factors. In horizontal counter-current experiments, chemical additives shifted flow dynamics toward counter-current dominance in the absence of gravity effects. In the gas recovery experiments, O342 effectively reduced water invasion in gas-saturated matrix at the early stage with reduced swept area and high residual gas retention. This suggested its potential for mitigating water-blocking effects in hydraulic fracturing operations. Oil recovery experiments conducted in a micromodel further confirmed the effectiveness of Tween 80 in suppressing viscous fingering and improving sweep efficiency. Additionally, the presence of Tween 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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