Search

The core pore structure of the target shale oil block was finely characterized using scanning electron microscopy， and a microscopic numerical model of the pore-scale core was constructed to elucidate the intrinsic mechanisms and the main controlling factors of spontaneous imbibition of fracturing fluid within the complex pore space of shale. On this basis， research was conducted on spontaneous imbibition within the fracture-matrix system. The Navier-Stokes （N-S） equations were coupled with the level-set method to track changes in the oil and water interface， thus clarifying the oil and water two-phase flow characteristics and evaluating the efficiency of spontaneous imbibition under the influence of the wettability， viscosity ratio of oil and water， and interfacial tension. The research results revealed that large and small intercommunicating pores in shale form intricate microscopic displacement units under capillary action. When the rock wettability presents a water-wet state， water preferentially infiltrates from the fracture into the smaller pores， expelling oil from larger pores into the fracture， and the produced range of crude oil within the matrix pores is wider， resulting in higher spontaneous imbibition efficiency. When the rock wettability turns oil-wet， crude oil within the small pores cannot be produced during spontaneous imbibition， while the water invades from larger pores， causing crude oil to be displaced from other large pores. This results in a lower spontaneous imbibition efficiency and a small range of crude oil produced in the matrix pores. The spontaneous imbibition in the initial phase is faster but gradually slows over time. Stronger water wettability of shale indicates a lower viscosity ratio of oil and water and higher interfacial tension， resulting in a wider range of crude oil produced within the matrix pores and a cumulative efficiency of spontaneous imbibition of more than 15%.

CO2 applications for enhanced oil recovery and storage in continental shale reservoirs are promising, and there is a need to evaluate the impact of porous structure on oil–water two-phase flow under CO2 environment. In this study, first, digital cores of quartz-rich, carbonate-rich, and clay-rich shales are established using Focused Ion Beam Scanning Electron Microscopy scanning data processed through generative adversarial networks. Subsequently, the pore networks generated by digital cores are quantitatively analyzed using the generalized extreme value distribution. Finally, pore network modeling is carried out to elucidate the effect of porous structural differences on oil–water flow considering CO2 dissolution and capillary forces. The results show that quartz-rich shale, characterized by nanopore intergranular dominance and the highest pore network connectivity, demonstrates the highest relative permeability of the oil phase. Carbonate-rich shale exhibits intermediate relative permeability of oil phase, while clay-rich shale exhibits the worst. The dissolution of CO2 reduces oil–water interfacial tension and oil viscosity, enhances oil mobilization within nanopores, and notably increases the relative permeability of the oil phase. The permeability of the oil phase is governed by pore structure, displaying positive correlations with core heterogeneity, pore radius, coordination number, and throat length, and negative correlations with throat radius. [ABSTRACT FROM AUTHOR]

Based on the CO2-WAG (water-alternating-gas) flooding for conventional reservoirs, CO2-WAG huff-n-puff in shale reservoirs is proposed. To clarify the phase behavior and fluid flow of oil–CO2–water in the CO2-WAG huff-n-puff process, a series of experimental studies are conducted under different injection sequences of CO2 and water. The results show that the saturation pressure of the oil–CO2–water systems is lower than that of the oil–CO2 systems since a portion of the CO2 is dissolved in water. In addition, CO2 injection followed by water can significantly reduce the dissolution of CO2 in the water. CO2 and water preferentially flow into the macropores and bedding fractures of the oil-saturated cores at the injection stage, and the oil in mesopores and micropores reflows into macropores and bedding fractures at the soaking stage. At the depressurization production stage, the oil in mesopores and micropores is gradually extracted. Compared to water injection followed by CO2, injecting CO2 first can avoid the barrier effect caused by the subsequent injection of water and promotes oil flow into mesopores and micropores in the matrix. At the end of production, the oil recovered from water injection followed by CO2 mainly originates from macropores, while that from CO2 injection followed by water primarily comes from mesopores. [ABSTRACT FROM AUTHOR]

The current oil recovery of the Lucaogou shale oil reservoir is predicted to be about 7.2%. It is crucial to explore improved oil recovery (IOR) technologies, and further experimental and field research needs to be conducted to study the complex mechanism. In this study, laboratory experiments were carried out to investigate the performance of one-step and multi-step depletion, CO2 huff-n-puff, and surfactant imbibition based on nuclear magnetic resonance (NMR). The sweep efficiencies were assessed via NMR imaging. In addition, hybrid methods of combining surfactant with CO2 huff-n-puff and the performance of injection sequence on oil recovery were investigated. The experimental results indicate that oil recoveries of depletion development at different initial pressures range from 4% to 11%. CO2 huff-n-puff has the highest oil recovery (30.45% and 40.70%), followed by surfactant imbibition (24.24% and 20.89%). Pore size distribution is an important factor. After three more cycles of surfactant imbibition and CO2 huff-n-puff, the oil recovery can be increased by 11.27% and 26.27%, respectively. Surfactant imbibition after CO2 huff-n-puff shows a viable method. Our study can provide guidance and theoretical support for shale oil development in the Lucaogou shale oil reservoir. [ABSTRACT FROM AUTHOR]

To address the problems of low recovery rate and poor water injection huff-n-puff effect in the depleted development of Jimsar shale oil. A study on the applicability of CO2 huff-n-puff technology in shale oil reservoirs was carried out by means of hydrocarbon phase experiments and numerical simulation methods for reservoirs to guide the implementation of CO2 huff-n-puff technology in the field. The results show that Compared with CH4, CO2 interacts better with Jimsar shale oil. Under the conditions of formation pressure and formation temperature, the solution gas-oil ratio of CO2 in crude oil is 497. 83 m³ / m³, the crude oil viscosity is reduced by 70. 65%, and the crude oil volume is expanded by 2. 05 times; for typical shale oil wells, multi-cycle CO2 huff-n-puff can improve the recovery rate by 9. 43 percentage points and crude oil production by 31 472. 40 t. With the shortening of frac- ture spacing and the increase of reservoir porosity, the effect of CO2 huff-n-puff on oil enhancement gradually becomes better, and the influence of permeability and oil saturation on the effect of CO2 huff-n-puff is relatively small. The results of the field test show that CO2 huff-n-puff can effectively enhance the recovery rate of shale oil, and the oil enhancement effect is better under the condition of no fracture disturbance. The research results have some implications for the efficient development of shale oil. [ABSTRACT FROM AUTHOR]