Shale reservoirs are characterized by low porosity，low permeability，and difficulty in exploitation，typically requiring the development approach combining long horizontal wells with large-scale volume fracturing techniques. After the fracturing fluid enters the formation，it undergoes a series of physical and chemical reactions with the reservoir，where salt ion diffusion plays a significant role. However，the existing research on the mechanism of ion diffusion and its application to diagnosing hydraulic fracture network is still imperfect. Therefore，this paper combines theoretical analysis with field cases to summarize the sources of salt ions in shale reservoirs，and the characteristics，mechanisms and influencing factors of ion diffusion，and presents an example of diagnosing hydraulic fracture network based on salt ion diffusion. The sources of salt ions in shale reservoirs include dissolved salts in the water film on the pore walls，crystallized salts from hydrocarbon generation and water expulsion，and salts produced by water-rock interactions. The characteristics of ion diffusion are similar to the imbibition process，which is divided into three stages：initial，transitional，and late diffusion. The initial ion diffusion rate is relatively high，exhibits a linear relationship on a logarithmic time scale，and follows Fick's law and the Einstein-Smoluchowski equation. The factors affecting salt ion diffusion include reservoir properties，solution properties，and other factors such as temperature and viscosity. Saltion diffusion can be used for the diagnosis of the development degree of volume fracturing fracture network. The method of diagnosing hydraulic fracture network through salt ion diffusion can provide scientific guidance for shale reservoir fracturing design and fracture network evaluation，help to deliver more accurate and effective reservoir stimulation and promote the efficient development and utilization of shale oil and gas resources.

In view of the limitations of traditional polymer and surfactant solutions in enhancing oil recovery，such as low viscosity retention and large adsorption loss，this paper examines the potential use of nanofluids for enhanced oil recovery and discusses recent research in this field. First，the synthesis of nanomaterials is described，and the methods used for evaluation of the stability of nanofluids in enhanced oil recovery in the field are summarized. Second，six mechanisms by which nanofluids enhance oil recovery are reviewed. These are：reducing interfacial tension，changing wettability，reducing crude viscosity，improving foam stability，structural disjoining pressure，and reducing pressure and increasing injection. Third，the use of nanofluids for enhanced oil recovery in the field is investigated. The “bottleneck” issues that limit the large-scale application of nanofluids in oilfields are also described. For example，there are currently no nanofluid flooding systems available for efficient development of unconventional reservoirs. Furthermore，there has been insufficient theoretical and technical discussion and research. More integrated research is required on inter-related matters such as the development of nanofluids containing two-dimensional nanosheets，determination of the mechanisms for enhanced oil recovery，and field pilot testing of the process. Finally，a direction for the practical introduction and application of nanofluids is proposed.

Well shut-in after fracturing is of great importance for increasing the oil recovery and production of shale oil reservoirs. The key is to determine the shut-in time. At present，there is no systematic and effective method for determining the time of shut-in either in China or across the world. The pressure transmission of the fracture system，the ion diffusion of the produced fluid and the capillary force imbibition are the key problems to be solved for addressing the above challenges. With laboratory experiments and field analysis，a comprehensive determination method for the shut-in time for Jimsar shale oil reservoirs was developed by clarifying the microscopic pore characteristics，wettability，laminae，and imbibition flooding potential of Jimsar shale oil reservoirs and analyzing the existing methods used and characteristics of shut-in time determination. It is concluded that the Jimusar shale oil reservoir provides strong imbibition and diffusion ability，and well shut-in after fracturing contributes to the displacement of oil. The shut-in time can be determined comprehensively in accordance with the required equilibrium time of the wellhead pressure，imbibition，and production fluid salinity. To determine the post-fracturing shut-in time for Jimsar shale oil reservoirs，the synergy of micro-fracture fluid charging and matrix imbibition should be taken into consideration. Specifically，with the second turning point of wellhead pressure decline taken as the lower limit and the turning point for the stable rising of salinity as the upper limit，the optimal shut-in time is determined，considering the imbibition equilibrium. The shut-in time after fracturing for Well Q was optimized based on laboratory experiments and field data. The suggested shut-in time for Well Q is about 55 days. This study provides an important reference for optimizing the shut-in time after fracturing.