Fracturing is a fundamental technique for enhancing oil recovery of tight sandstone reservoir. The pores in tight reservoirs generally have small radii and generate tremendous capillary force; accordingly, the imbibition effect can significantly affect retention and absorption of the fracturing fluid. In this study, the imbibition behaviors of the fracturing fluid were experimentally investigated, and the effects of interfacial tension, (IFT) permeability, oil viscosity, and the salinity of the imbibition fluid were determined. In addition, combining with nuclear magnetic resonance (NMR)-based core analysis, fluid distribution, and the related variations in imbibition and displacement processes were analyzed. Finally, some key influencing factors of imbibition of the residual fracturing fluid, the difference and correlation between imbibition and displacement, as well as the contribution of imbibition to displacement were explored so as to provide optimization suggestions for guiding the application of oil-displacing fracturing fluid in exploration. Results show that imbibition recovery increased with time, but the imbibition rate gradually dropped. There exists an optimal interfacial tension that corresponds to maximum imbibition recovery. In addition, imbibition recovery increased as permeability and salinity increases and oil viscosity decreases. Furthermore, it was found that extracted oil from the movable pore throat space was almost equal to that from the irreducible pore throat space during imbibition and their contribution in the irreducible pore throat space was greater than in the movable pore throat space in the displacement process. Hence, imbibition plays a more important role during the displacement process in the reservoirs with finer porous structure than previously thought.

Adsorption is one of the most important forms of storage of gas in shale reservoirs. Shale gas adsorption in the actual reservoir is not only affected by individual factors such as water content, temperature, and pressure but also by the synergetic effect of these factors. In this study, we conducted laboratory experiments on methane adsorption in dry and wet shale at different pressures and temperatures. The synergetic effect of water content, temperature, and pressure on shale gas adsorption is explored. The results show that increasing temperature weakens the interaction between methane and shale and reduces adsorption capacity due to the exothermic nature of adsorption. Water reduces methane adsorption capacity by occupying adsorption sites and blocking pores in the shale system. Although temperature and water reduce methane adsorption individually, the effect of these two factors weakens each other. Temperature has a more significant effect on methane adsorption in shales with low water content, while water has a more remarkable impact on methane adsorption at a low temperature. Furthermore, the increase in pressure reduces the negative influence of water and temperature on methane adsorption. By quantitatively analyzing the relationship between methane adsorption in dry and wet shales, a predictive adsorption model for wet shale considering the influence of in situ conditions is proposed and validated. Validation shows that the proposed model has high accuracy and broad applicability to shales with different properties.

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Methane adsorption and desorption in shale can significantly be affected by water due to the water-bearing depositional environment of shale and the application of hydraulic fracturing technology in shale gas production. The characteristics of shale gas adsorption and desorption are comprehensively affected by the temperature, pressure, and especially, the water content in the reservoir. To further explore the impact of water on shale gas adsorption and desorption, the adsorption-desorption experiments of methane in waterbearing shale at different temperatures and different pressures are performed. Afterward, the adsorption behavior and desorption hysteresis are characterized by employing the Langmuir model and Langmuir+λ model. Finally, the ways of the pressure, temperature, and water combinedly affect shale gas adsorption behavior and desorption hysteresis are analyzed. The results show that adsorption and desorption of methane in the water-bearing shale are irreversible, which are consistent with the Langmuir model and the Langmuir+λ model, respectively. An increase in temperature will reduce adsorption and promote desorption, as an increase in temperature essentially enhances the thermal movement of methane molecules. Water lowers the adsorption and desorption of methane in shale, as the water molecules occupy the adsorption sites in organic pores and clay mineral pores in different ways. However, the effect of temperature and water content on adsorption is closely related to the pressure. The lower the pressure, the more significant the effect of temperature and water content. The combined effect analysis demonstrates that the impact of water on methane adsorption in shale is much more significant than that of the temperature. Still, desorption is simultaneously affected by both temperature and water content. As the pressure decreases in the desorption process, the desorption rate is dominantly affected by water when the pressure is lower than 8 MPa, and the desorption rate is aggressively affected by temperature when the pressure is at above 8 MPa.

To solve the problem of poor adaptability of the single slug polymer injection mode which lead to profile inversion, non-effective circulation of polymer solution in the high permeability zone during the development of conventional heavy oil, new technology of alternative injection, and three-stage slug injection for further improving polymer flooding performance were developed. Parallel sandpack flooding experiment was conducted to study the oil displacement efficiency of different injection modes, and reasonable injection mode and optimal slug combination of polymer flooding are selected. The results show that under the same polymer dosage, the high and low mass concentration polymer slug alternative injection is better than the three-stage slug and single slug polymer flooding, and with the increase of the alternating rounds, the polymer flooding performance increased first and then decreased. Compared with the single slug injection, the alternative injection increased the recovery factor by 4%. When the three-stage slug is injected, the concentration of the front and post slug has a significant effect on the oil displacement process. The optimal oil displacement formulations are as follows: main slug 5000 mg/L × 0.125 PV, secondary slug 3000 mg/L × 0.208 PV, alternating two rounds.