Opening-mode fractures play a crucial role in shale reservoirs, as they serve as flow channels and provide storage space for hydrocarbons. The shale reservoirs in the Permian Lucaogou Formation of the Junggar Basin, NW China, record multi-stage tectonic and diagenetic processes that created multi-stage natural fractures, thereby contributing to the oil content differentiation within the formation. Effective identification and characterization of natural fractures is vital for the efficient recovery of shale oil in the Jimsar Sag. We combine outcrop observations, drill core analyses, thin section examinations, and well log analyses to determine the characteristics of fractures in the shale reservoirs and their modes of development. We also establish multi-parameter evaluation index criteria and an evaluation system for fractures using statistical analyses. The shale reservoirs of the Lucaogou Formation in the Jimsar Sag host three main types of fracture: tectonic fractures, diagenetic fractures, and overpressure fractures. Conventional well logging, imaging logging, and core observations demonstrate that the fractured shale reservoir section has gamma-ray counts (GR) of >75 API, shallow laterolog resistivities of <80 Ω·m, neutron densities of <2.40 g/cm³, neutron porosities of >27%, and interval transit times of >23.77 μs/m, fracture density exceeding 3 fractures/m, and average porosity ranging from 0.2% to 0.3% in the lower sweet spots. The lower sweet spot (P₂l₁²) of the Lucaogou Formation exhibits the highest degree of fracture development. Our detailed characterization reveals high fracture permeabilities and porosities in the upper and lower sweet spots (P₂l₂² and P₂l₁²), with higher values in the latter. In addition, we present a novel rose diagram method to represent various fracture parameters. The best-developed tectonic fractures in the Lucaogou Formation strike ENE–WSW, have an average linear density of 1.65 fractures/m, an average aperture of 0.25 mm, an average length of 8.7 cm, and the highest proportion of unfilled fractures. Our study shows that a combination of field observations, drill core analyses, microscopic observations, and well logging provides a solid foundation for investigating the mechanisms of fracture formation in shale reservoirs.

The key factors controlling the densification of unconventional reservoirs (e.g., tight oil and gas reservoirs) remain poorly understood and directly affect the distribution of exploitable resources. Here, systematically explored reservoir characteristics, depositional microfacies, and the main factors controlling densification of the tight oil reservoir in the Chang 8 Member (Yanchang Formation, Middle Triassic) in the southern Ordos Basin by thin section analysis, scanning electron microscopy, physical property measurement, X-ray diffraction, and mercury injection. Our results confirm the Chang 8 reservoir as an extremely low permeability tight sandstone reservoir mainly comprising lithic feldspathic sandstone with various primary and secondary pores and fine pore channels. The highest quality reservoir is mainly restricted to the middle and lower parts of subaqueous distributary channel microfacies. Dissolution partly contributed to reservoir formation, but the persistence of early, non-compressed storage space was more important. The compression of plastic rock debris removed a significant amount of porosity, and calcite, kaolinite, and siliceous minerals both fill pores, whereas chlorite cladding of particles protects the pore space. We identified three densification mechanisms: the persistent densification of highly plastic rock debris during burial, calcite cementation and pore filling, and feldspar dissolution and subsequent kaolinite precipitation and siliceous cementation. After their compaction, the Chang 8 Member reservoirs were charged with hydrocarbons. We applied clustering analysis to eight reservoir characteristics (porosity, permeability, median pore-throat radius, maximum pore-throat radius, median capillary pressure, pore discharge pressure, chlorite content, kaolinite content) to quantitatively classify the Chang 8 reservoir into three categories. Type-Ⅰ reservoirs have the best conditions for hosting tight oil reservoirs, with ~12% porosity, permeabilities of ~0.2 × 10⁻³ μm², trial oil production rates of >5 m³/d, and, indeed, occur in subaqueous distributary channel microfacies. Type-Ⅱ reservoirs ~10% porosity, permeabilities of ~0.1 × 10⁻³ μm², and trial oil production rates of 1–5 m³/d. Type-Ⅲ reservoirs have ~5% porosity, permeabilities of ~0.05 × 10⁻³ μm², and trial oil production rates <1 m³/d. These results provide an important basis for predicting the distribution of exploitable zones in the Chang 8 Member and other adjacent tight reservoirs.