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The key to the efficient development of a tight reservoir is its accurate evaluation. In this study, the pore throat structure characteristics of sandstone samples in the study block were analyzed by high-pressure mercury injection technology. According to the characteristics of the capillary pressure curve, the sandstone samples in the study block were divided into three types: the first type has a reservoir permeability greater than 0.7 mD and a core mercury injection saturation of 96% with a good reservoir quality; the second type has a reservoir permeability ranging from 0.4 to 0.7 mD and a core mercury injection saturation of 80% with a moderate reservoir quality; and the third type has a reservoir permeability between 0.1 and 0.4 mD and a core mercury injection saturation of 50% with a poor reservoir quality. Also, high-resolution synchrotron radiation imaging and scanning electron microscopy were used to observe the pore throat structure, connectivity, and microscopic heterogeneity of sandstone samples, showing an increasing level of pore disconnection, serious microscopic heterogeneity, and poor reservoir performance as reservoir permeability declines. As mineral composition tests show, the lithology of the tight sandstone in the target block is mainly medium-grained and fine-grained feldspar lithic sandstone and the longitudinal heterogeneity of lithology and mineral components of tight sandstone is relatively weak at above the centimeter level. Besides, based on the high-pressure mercury injection test data, fractal theory is applied to calculate the fractal dimensions of the three types of reservoirs. The result shows a gradual increase in fractal dimensions with the decrease of reservoir quality, in which the closer the fractal dimension is to 3, the more serious the microscopic heterogeneity is, and the stronger the roughness of the pore surface is. As a result, the more heterogeneous the tight reservoir gets, the more likely the injected fluid is to flow along the developed and connected pore regions.

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The Chang 8 (C8) reservoir is a transitional oil pool type from a tight oil sandstone to a lithologic trap in the Upper Triassic Yanchang Formation of the Honghe oil field, southwest Ordos Basin, China. Vertical faults play important roles in the formation and distribution of the sweetness. To predict favorable high-yield well areas and guide horizontal well deployment, 3D seismic data are used to analyze these faults’ distribution, formation phase, stress property, and control on the oil accumulation. The results indicate that the X shape of the east–northeast and north–northeast conjugate shear faults were formed during the Indosinian epoch, and the northwest faults were formed during the Yanshan epoch. Meanwhile, the earlier east–northeast faults partially experienced reactivity and rework later but the north–northeast faults ceased since the Indosinian. The strike-slip faults in the area are classified into three categories based on their intensity, density, formation stage, and oil control effectives: types I, II, and III. The type I faults extended in the northwest and east–northeast directions and were cut from the Ordovician up to the top Cretaceous. They are characterized by the maximum extensions aerially and vertically thereby faulting the thickest strata. Type II faults mainly extended in the east–northeast direction and were cut from the Triassic up to the top Cretaceous in small intension. Type III faults mainly extended in the north–northeast direction and were cut from the Ordovician up to the Upper Permian. The faults connect the C8 sandstone reservoir and the Chang 7 source shale by penetrating the interlayered silty mudrock in between them. The low permeable reservoir also requires additional permeability imparted by the type I faults. High-yield horizontal wells are distributed along intensive type I faults. The water-bearing zones or oily water zones are mostly related to no fault or to the type II and III faults.