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The distribution of the deep geothermal field and the tectonic thermal control mode in the Yingshan area were not understood systematically, which would bring in constraints to the sustainable exploration of local geothermal resources. Based on the field survey on continuous temperature, fracture measurements in the outcrops of granite rock, slug-test, and pumping test in the boreholes, a three-dimensional model coupling fluid flow and heat transfer process in fractured rock reservoir was established. Then the distribution of fluid pressure temperature and the Darcy velocity in the whole geothermal reservoir were calculated considering different treatment combinations of main faults. The results show that the deep temperature field and fluid pressure distribution are greatly affected by the faults system. At the location of bedrock and impermeable fault, the fluid movement is very weak, and the heat transfer is mainly controlled by heat conduction, while in the high permeable fault, it is mainly controlled by heat convection. Low temperature and fluid pressure occurred in the deep, high-permeable fault zone whereas high fluid pressure occurred in the impermeable fault zone. At a depth larger than 2000 m, the zones with high temperatures and intense hydraulic exchange coincide with the conductive fault zones, which indicates that the high-permeable faults are the most important channel for seepage and heat transfer in the reservoir. Therefore, the northeast faults are the dominant channel for fluid migration and heat conduction in the Yinshan area. Hot water migrates upward along the northeast faults and is blocked by the north-south fault. The hot spring is formed at the intersecting position of two groups of faults. This study is helpful for scientific, sustainable exploration of geothermal resources in the Yingshan area.

Salt precipitation is an important issue for CO2 sequestration in deep aquifers.At present, most numerical simulations ignore the feedback effect of the changes in the porosity and permeability caused by the salt precipitation on fluid flow.In this paper, taking Liujiagou Formation in Ordos Basin as an example, a two-dimensional model is established using TOUGH2 code.By modifying the source code of the program, the model can consider the feedback effect of salt precipitation on fluid flow.The simulation results show that after the CO2 injection into the Liujiagou Formation for 20 years, salt precipitation makes the formation pressure near the injection well increase by 0.87MPa and the corresponding injectivity loss of the formation is 7.17%.The salinity has the greatest influence on salt precipitation and its feedback, followed by CO2 injection rate, and permeability has the least influence.When the salinity is high, solid salt saturation increases significantly, resulting in a great decrease in the permeability.In this study, when the salinity was 0.24, the salt precipitation caused an injectivity loss by 45.32% and the pressure buildup up to 12.14 MPa.Therefore, special attention should be paid to the salt precipitation caused by high salinity and its feedback effect during CO2 storage.