Tight sandstone reservoirs are of interest due to their potentially favorable prospects for hydrocarbon exploration. A better understanding of tight sandstone outcrop reservoir characteristics and their influencing factors is thus needed. By laboratory observation, thin section analysis, and experimental analysis, the current work carried out a detailed investigation of densely sampled tight sandstone outcrops of the Shanxi Formation in the Liujiang River Basin, paving the way for further research on rock types, reservoir spatial distribution, physical properties, and their key controlling factors. The application of the Pressure Pulse Attenuation Method made it possible to determine the porosity and permeability, as well as the analysis of debris composition and filling content. The findings indicate that the main rock type of the tight sandstone outcrop reservoirs in the Shanxi Formation in the Liujiang River Basin is lithic quartz sandstone, some of which contains fine sand-bearing argillaceous siltstone, giving them very low porosity (average porosity of 4.34%) and low permeability (average permeability of 0.023 mD) reservoirs. Secondary pores—mostly dissolved pores among and in grains—are widely developed in the target region. In addition, diagenesis primarily includes mechanical compaction, cementation, and dissolution. The main controlling factors of tight sandstone reservoirs in the target region are sedimentation, diagenesis, and tectonics, whereby sedimentation affects reservoir physical properties that become better as the clast size increases, reservoir properties are negatively impacted by compaction and cementation, and reservoir properties are somewhat improved due to dissolution and the impact of tectonism. In addition, the tilt of the crust will produce faults during the tectonic action, generating reservoir cracks that improve the reservoir’s physical properties. This study tends to be helpful in the prediction of high-quality reservoirs in the Permian Shanxi Formation in North China and can also be used for analogy of high-quality reservoirs in similar areas with complete outcrops.

The lateral sealing of a fault plays a pivotal role in the efficacy of a fault trap and its degree of hydrocarbon filling. Nevertheless, the evaluation of this phenomenon remains a challenging task, with evaluation methods either unable to accurately reflect subsurface reality or obtaining the necessary parameters difficult. In light of these considerations, a porosity-based fault laterality evaluation method was proposed, with the F1 Fault of the Nanpu No. 5 structure in the Nanpu Sag serving as the research object. First, the relationship between porosity and the product of burial depth and shale content was established using measured porosity, burial depth, and shale content data of the surrounding rocks in the study area. Subsequently, the reservoir rock porosity was obtained by employing logging data or core samples or by calculating the reservoir rock shale content from natural gamma logging data. Concurrently, the shale content of fault rock was calculated using three-dimensional (3D) seismic data, mud logging data, and natural gamma logging data, thereby enabling its porosity to be determined. Finally, the porosity difference between the two was employed to assess the lateral closure of faults. The results indicate that the porosity difference is less than 0 at lines L1~L3 of the F1 Fault, which suggests that the fault is not laterally closed at this site. Conversely, the F1 Fault is laterally sealed at this location, as indicated by the porosity difference being greater than 0 at lines L4~L10. The findings of this evaluation were found to be in close alignment with the actual distribution of oil and water, indicating that the proposed method can accurately evaluate the lateral closure of faults with developed fault rocks and provide valuable guidance for the exploration of faulted oil and gas reservoirs.

The Daheishan Horst is located in the eastern segment of the Solonker-Xar Moron River-Changchun-Yanji Suture (SXCYS), between the eastern margin of the Songliao Basin and the Jiayi Fault Zone. The Daheishan Horst serves as a critical area for studying the evolutionary processes of the eastern Paleo-Asian Ocean (PAO). Current debates persist regarding the formation age, tectonic setting, and evolution of magmatic rocks in the Daheishan Horst. To address these controversies, this study examines diorite porphyry dikes exposed in Heibei Village, Jilin City, Jilin Province, through comprehensive analyses including: whole-rock major, trace, and rare earth elements; zircon U-Pb dating; zircon Hf isotopes; and whole-rock Sr-Nd isotopes. These investigations aim to determine the formation age and tectonic evolution of the magmatic rocks in the Daheishan Horst. Key findings include: (1) Zircon U-Pb ages (252.9 ± 3.2 Ma) indicate Late Permian emplacement; (2) The magmatic rocks are predominantly subalkaline and belong to the medium-K calc-alkaline series. They exhibit enrichment in large-ion lithophile elements (LILEs) and light rare earth elements (LREEs), with significant depletion in high-field-strength elements (HFSEs: Nb, Ta, P, Ti), consistent with arc-type or active continental margin magmatism; (3) Zircon Hf and whole-rock Sr-Nd isotopic analyses indicate magma derivation primarily from partial melting of depleted mantle sources, with negligible contamination from ancient crustal materials; (4) Geochemical signatures include positive La/Sm-La correlations, elevated Th contents (6.21–11.66 ppm), Th/Yb = 2.52–3.66, Zr/Y = 9.7–11.5, and Ta/Yb = 0.12–0.28. These features are diagnostic of oceanic-continental subduction zone magmatism, confirming origination from partial melting of subduction-fluid-metasomatized mantle. This study concludes that the magmatic rocks of the Daheishan Horst formed during subduction beneath an active continental margin. Our results reveal a bidirectional subduction with scissor-like closure model along the SXCYS in the eastern Paleo-Asian Ocean, with closure propagating westward to eastward from the Late Permian to Early/Middle Triassic.

Fracability serves as the dominant factor governing the recoverable conditions of shale oil reservoirs. Based on logging data from the Cretaceous Qingshankou Formation in the central Daqing Placanticline, China, combined with core experimental data, correlation analysis, and the analytic hierarchy process (AHP) for weight calculation of fracability evaluation indices, this study establishes a fracability parameter interpretation model for the area. The calculation results are highly consistent with test and analytical data, featuring high accuracy and satisfying fracability evaluation demands. The results show that the Cretaceous Qingshankou Formation in the study area is characterized by a low–medium Young’s modulus, high Poisson’s ratio, high brittleness index, low stress difference, and a normal faulting stress regime. For the first member of the Qingshankou Formation, Young’s modulus ranges from 6.7 to 21.4 GPa, Poisson’s ratio from 0.26 to 0.41, brittleness index from 34.1 to 58.4%, stress difference from 1.67 to 2.41 MPa, and fracability index from 0.26 to 0.79. Class II fracability dominates the central region horizontally, with a small amount of Class I in the southeastern and western parts. Regarding the reservoirs in the second and third members of the Qingshankou Formation, Young’s modulus is 9.6–19.5 GPa, Poisson’s ratio is 0.31–0.39, the brittleness index is 39.5–50.3%, the stress difference is 1.76–2.28 MPa, and the fracability index is 0.39–0.77. Both Class I and II are well developed: Class I is mainly distributed horizontally in the western, southern and northeastern regions, while Class II shows a curvilinear zonal distribution in the central area.

The Shahejie Formation in Nanpu Sag is a crucial region for deep-layer hydrocarbon exploration in the Bohai Bay Basin. To address the impact of faults on sublacustrine fan formation and spatial distribution within the study area, this study integrated well logging, laboratory analysis, and 3D seismic data to systematically analyze sedimentary characteristics of sandbodies from the first member of the Shahejie Formation (Es₁) sublacustrine fans, clarifying their planar and cross-sectional distributions. Further research indicates that Gaoliu Fault activity during Es₁ deposition played a significant role in fan development through two mechanisms: (1) vertical displacement between hanging wall and footwall reshaped local paleogeomorphology; (2) tectonic stresses generated by fault movement affected slope stability, triggering gravitational mass transport processes that remobilized fan delta sediments into the central depression zone as sublacustrine fans through slumping and collapse mechanisms. Core observations reveal soft-sediment deformation features, including slump structures, flame structures, and shale rip-up clasts. Seismic profiles show lens-shaped geometries with thick centers thinning laterally, exhibiting lateral pinch-out terminations. Inverse fault-step architectures formed by underlying faults control sandbody distribution patterns, restricting primary deposition locations for sublacustrine fan development. The study demonstrates that sublacustrine fans in the study area are formed by gravity flow processes. A new model was established, illustrating the combined control of the Gaoliu Fault and reverse stepover faults on fan development. These findings provide valuable insights for gravity flow exploration and reservoir prediction in the Nanpu Sag, offering important implications for hydrocarbon exploration in similar lacustrine rift basins.

Regional mudstone cap rock has an important influence on the oil and gas distribution of the oil source faults below it. Therefore, studying the influence of these mudstone cap rocks on the hydrocarbon distribution pattern is fundamental to understanding the oil and gas distribution of the lower generation and upper reservoir reservoirs in the Bohai Bay Basin. This study classified two types of hydrocarbon diversion from oil source faults: blockage diversion and seepage diversion. To locate them, we established a method to predict the areas with blockage diversion and seepage diversion separately by superimposing the sealing and leakage parts of the regional mudstone cap rock with the regions of the connected distribution of sand bodies and the favorable hydrocarbon transport sites of the oil source faults, respectively. We used this approach to predict the locations where hydrocarbons are diverted by the oil source faults under the regional mudstone cap rocks in the first and second sections of the Dongying Formation (E₃d_1-2) in the Liuchu area of the Raoyang Sag, Bohai Bay Basin. The results show that the regional mudstone cap rock’s blockage diversion occurs mainly in the south-central area of Liuchu, with a localized distribution in the northern part. The seepage diversion site is primarily located in the northeastern area and is also found locally in the west. Both diversions are beneficial for the accumulation of hydrocarbons from the source rocks of the first member of the Shahejie Formation (E₃s₁) to the upper second member of the Dongying Formation (E₃d_2U). The latter can also accumulate hydrocarbons in the Guantao Formation (N₁g). The results align with the hydrocarbon distribution, demonstrating the feasibility of our method to predict various oil source fault diversion sites under the regional mudstone cap rock. This prediction method offers valuable guidance for exploring the lower generation and upper reservoir hydrocarbon accumulations in hydrocarbon-bearing basins.