Characteristics and distribution of tectonic fracture networks in low permeability conglomerate reservoirs

Natural fractures (particularly those reshaped by multiple tectonic stages) are of paramount importance for the development of tight conglomerate hydrocarbon reservoirs. These fractures not only enhance reservoir pore space but also serve as essential conduits for hydrocarbon migration. Focusing on the Permian Jiamuhe Formation conglomerate reservoirs in the Xiaoguai area of the Junggar Basin, this study integrates structural interpretation, core observation, and well-log evaluation to elucidate the characteristics and vertical distribution of tectonic fractures. A paleotectonic stress field numerical simulation is subsequently employed to predict their planar distribution. Results indicate that the Jiamuhe Formation primarily comprises fracture-type and fracture-porosity-type reservoirs, wherein granule and pebble conglomerates predominate. Tectonic fractures are a pivotal control on reservoir quality. They predominantly manifest as shear fractures formed under compressional stresses, with dip angles exceeding 75°, consistent with regionally extensive tectonic fractures. Such fractures are chiefly developed in fine conglomerates, gravelly sandstones, and heterogeneous sandstones adjacent to fault zones, corresponding to delta front and delta margin subfacies. Well-log interpretations suggest that fractures are more pronounced in the middle to upper sections of the Jiamuhe Formation. However, their thickness is often limited, varies considerably, and exhibits marked heterogeneity, limiting straightforward well-to-well correlations. Using the finite element numerical simulation software "2D-σ," coupled with an elastic constitutive model and a Mohr-Coulomb failure criterion, we characterized the degree of rock failure and delineated the paleotectonic stress field and associated fracture distribution. Production data integrated with geological analyses facilitated the classification of fracture development zones into three discrete levels. Grade I fracture development zones, trending northeast-southwest (NE-SW), are predominantly subjected to northwest-southeast (NW-SE) compressive stresses and exhibit high stress values, large stress differentials, and high degrees of rock failure. A comparison of single-well production with simulation outcomes reveals that wells intersecting extensively developed fracture systems generally yield superior oil-test performances, underscoring the critical role of fractures in hydrocarbon migration and entrapment. The paleotectonic stress field numerical simulation method has thus demonstrated robust reliability for predicting tectonic fractures. Accurate identification of fracture development zones is instrumental in improving exploration success rates and optimizing hydraulic fracturing strategies during reservoir development.