To investigate the mechanism whereby well shut-ins and surfactant additivities can increase hydrocarbon output after hydraulic fracturing, in this paper, we simulated well shut-ins with one end open (OEO) rock samples and performed a serious of imbibition experiments with different surfactant additivities based on contact angle (CA) and interfacial tension (IFT) measurements. Scanning electron microscope (SEM) and nuclear magnetic resonance (NMR) methods were also been adopted in the detection before and after shut-ins. The results demonstrated that cationic surfactants result in better improving oil recovery (IOR) performance due to their high wettability alteration ability on vertical fracture faces, while different kinds of surfactants have a similar ability in lowering IFT. As for shut-ins duration, the NMR transverse relaxation time (T₂) spectrum move towards the left side, indicating that aqueous phases migrate to smaller pores spaces and deeper distances. Aqueous migration during the shut-ins period can remove near-fracture trapped water, while surfactant additivities can accelerate and enhance this process, and these two points are the most direct reasons for the observed hydrocarbon output increases.

This study extensively investigates the influence of different pyrolysis temperatures and organic matter contents on the fluid flow and heat transfer properties in oil shale samples. Utilizing CT images to generate three-dimensional digital rock, coupled simulations of ${\mathrm{CO}}_2$ flow and heat transfer were conducted, analyzing parameters such as velocity fields, permeability, temperature fields, average temperatures, and heat transfer coefficients. The results reveal that, for relatively homogeneous oil shale samples, the permeability exhibits a monotonous increase with rising pyrolysis temperature. While the effect of pyrolysis temperature on the distribution characteristics of velocity and temperature fields is minimal, it significantly impacts the heat transfer coefficients. Specifically, the heat transfer coefficients increase significantly in the direction perpendicular to the bedding plane, while they decrease or remain unchanged parallel to it. Additionally, the organic matter content significantly influences the fluid flow and heat transfer properties of shale samples. After undergoing heat treatment, the heterogeneity of pore structures in shale samples varies significantly, affecting the characteristics of fluid flow and heat transfer. The influence of organic matter content and pyrolysis temperature on fluid flow and heat transfer in shale primarily stems from the effect of organic matter pyrolysis on the original pore structure. The development and connectivity of pore networks are closely related to the distribution characteristics of the original organic matter and are not directly correlated with the organic matter content. These findings provide essential theoretical guidance and technical support for the development and utilization of oil shale resources, while also offering valuable references and insights for future research.

Accuracy defects exist when modeling fluid transport by the classical capillary bundle model for tight porous media. In this study, a three-dimensional simplified physical model construction method was developed for tight sandstone gas reservoirs based on the geological origin, sedimentary compaction and clay mineral-cementation. The idea was to reduce the porosity of the tangent spheres physical model considering the synergistic effect of the above two factors and achieve a simplified model with the same flow ability as the actual tight core. Regarding the wall surface of the simplified physical model as the boundary and using the Lattice Boltzmann (LB) method, the relative permeability curves of gas and water in the simplified model were fitted with experimental results and a synergistic coefficient could be obtained, which we propose for characterizing the synergistic effect of sedimentary compaction and clay mineral-cementation. The simplified physical model and the results simulated by the LB method are verified with the experimental results under indoor experimental conditions, and the two are consistent. Finally, we have carried out a simulation of gas flooding water under conditions of high temperature and high pressure which are consistent with the actual tight sandstone gas reservoir. The simulation results show that both gas and water have relatively stronger seepage ability compared with the results of laboratory experiments. Moreover, the interfacial tension between gas and water is lower, and the swept volume is larger during placement. In addition, the binding ability of the rock surface to the water film adhered to it becomes reduced. The method proposed in this study could indicate high frequency change of pores and throats and used to reflect the seepage resistance caused by frequent collisions with the wall in microscopic numerical simulations of tight sandstone gas reservoirs.

Spontaneous imbibition is an important mechanism for fractured reservoir to enhance oil recovery. Wetting phase enters porous media with the force of capillary pressure and gravity and replaces oil in matrix. To investigate the imbibition of tight reservoirs, on the consideration of tight formation characteristics, this paper derived a one dimension, two phases, counter-current imbibition model, after dimensionless of distance and time, Galerkin method for spatial discretization and time integration, solutions were given, comparisons of conventional sandstone and tight formation were made. The results have indicated that: (1) Imbibition can be divided into gravity assisting, gravity opposing and zero gravity in terms of different gravity conditions. (2) Saturation front of tight formation moves faster than sandstone because of high capillary pressure. (3) Capillary pressure plays the dominant role than gravity in imbibition. Influence of gravity is much greater in high-permeability sandstone than in tight reservoirs. (4) Horizontal well multi-stage fracturing and massive fracturing can increase fracture area and fracture volume, and increase the contact area with wetting phases, this will result in a greater imbibition and a great recovery of oil.

In order to determine the effective stress factor of proppants during the multi-stage hydraulic fracturing operation in horizontal wells and select the appropriate proppant type, the analysis of the effective stress characteristics of proppants is carried out. This analysis considers the geomechanics and long-term production characteristics of multi-stage fractured horizontal wells in reservoirs like Xinjiang Mahu shale oil and Southwest China shale gas. The analysis of influencing factors is also carried out. The results show that, during the multi-stage hydraulic fracturing operation in horizontal wells, the stress on proppants is not only related to geological factors such as reservoir closure stress, but also closely related to total injection volume, cluster spacing, liquid type, injection displacement and post fracture management. First, increasing injection intensity, reducing fracture spacing, using low viscosity fracturing fluid, adopting high injection displacement and utilizing reasonable flowback system can effectively supplement reservoir energy, postpone the effective stress peak of proppants, and increase the effective conductivity of proppants. Second, the production performance analysis results of nearly 300 horizontal wells (from Xinjiang oil field, Erdos tight oil reservoir, Sichuan shale gas reservoir, etc.) shows that: the effective stress of proppants in horizontal wells is only 50–60% of that in vertical wells, which results in a different proppant selection criterion in the volume stimulation of horizontal wells and provides the geomechanics basis of replacing ceramsite proppant with quartz sand to reduce cost and increase efficiency. Based on the above conclusions, the field test of replacing ceramsite proppant with quartz sand was carried out. The proportion of quartz sand increased from less than 30% in 2014 to 69% in 2019. Without any impact on production, the annual investment cost was decreased by more than 1 billion yuan, which set a great example for the promoted low-cost development of unconventional oil and gas reservoirs under low oil price background.

Spontaneous imbibition is an important process to increase oil recovery in fractured carbonate reservoirs. Due to the nano-scale pores and throats distributed in tight oil reservoirs, capillary pressure became much larger, which may result in a much stronger imbibition. An experimental and modeling was adopted to simulate drainage and imbibition process in hydraulic fractured tight oil reservoir. Firstly, 400 mm×100 mm×30 mm core samples were used to simulate forced displacement and spontaneous imbibition of fracture surface at in-situ conditions of pressure. Secondly, 1D model for counter-current imbibition was solved on some assumption of relative permeability and capillary pressure, numerical results obtained by COMSOL as verification. Results have indicated that recovered oil was 0.19 mL in spontaneous imbibition condition while was 0.62mL in combined condition of forced displacement and spontaneous imbibition. Saturation front contacts the sealed end-face much faster with forced pressure condition. According to this phenomenon, it can be inferred that the main direction of aqueous phase in the shut-in period is form large pores to smaller pores. Aqueous phase was pushed into the large pores by forced pressure, and imbibed into smaller pores in the function of capillary pressure. 1D model of 2 phases counter-current imbibition solved with Galerkin method is in correspondence with numerical result at the same assumption. With the increase of dimensionless distance (X) and dimensionless time (T), water saturation profiles were drew and were contrasted with CT scanning. Forced displacement and spontaneous imbibition simultaneously occurs during fracturing and shut-in duration. Study of this can provide a reference for soaking management and a good way to increase well productivity.