The current methods of helium porosity measurement for continental shales tends to yield underestimated porosity due to insufficient equilibration time. Based on the experimental principle of helium porosity determination, we conduct an ultra-long-term (60 h) systematic test using the helium expansion method on shale samples of varying specifications under different injection pressures, based onthe continental freshwater lacustrine basin shale reservoir system. Accordingly, a helium porosity determination method for continental organic-rich shales is proposed. The results indicate that the key factors influencing helium porosity measurement include pore structure, equilibration time, temperature, and injection pressure, which significantly restrict the degree of helium saturation. A prolonged equilibration time can effectively enhance the accuracy of helium porosity measurement. For shale samples from the 1st member of the Cretaceous Qingshankou Formation (also referred to as the Qing 1 Member) in the Songliao Basin, the porosity measured under a test duration of 60 h increased by 19.50%~37.64% compared to that measured under a test duration of 25 min. Meanwhile, for the shale samples from the 3rd oil sub-group of the 7th oil group of the Triassic Yanchang Formation (also referred to as the Chang 73 oil sub-group) in the Ordos Basin, the porosity measured under a test duration of 60 h increased by 20.44%~45.10% compared to that obtained under a 25-min test. Crushed samples can effectively shorten the time for pressure equilibration for tests. It is recommended that the grain sizes of crushed samples should be 3-4 orders of magnitude of the dominant pore sizes. The helium saturation can be enhanced by extending the pressure equilibrium time and increasing the injection pressure. Furthermore, the experimental errors caused by the deviation of helium molecules from their ideal state can be reduced by introducing the compression factor, correction of weakly connected pores, and residual fluid correction. Shale reservoirs formed under different sedimentary systems exhibit different physical properties, pore types, and pore size distribution, as well as varying degrees of modification during the diagenetic evolution process. Therefore, the test conditions and experimental parameters for the helium porosity measurement should be determined based on the specific characteristics of shale reservoirs. It is recommended that the equilibration time should be set at equal to or longer than 36 h for shales from the Chang 73 oil sub-group and equal to or longer than 48 h for those from the Qingshankou Formation. A helium porosity-time prediction chart is developed in combination with numerical simulation, which can help reduce test costs and improve test accuracy.

The deep-water sedimentary system of Chang 7 in the Ordos Basin is a typical representative of deep-water gravity flow in large depression lake basins. Exploring the types, characteristics, fluid properties, and sedimentary evolution process of deepwater gravity flow sedimentation in Chang 7 based on centimeter level core descriptions, logging, and thin section data from multiple core wells. There are four types of deep-water sedimentation: deep lake mud shale sedimentation, landslide sedimentation, sandy debris flow sedimentation, and turbidity current sedimentation. The delta front sand body on the profile undergoes collapse under external force triggering conditions, transforming into sandpaper debris flow and ultimately evolving into turbidity current. On the plane, a large area of sandy debris flow tongue shaped bodies are developed at the end of the delta front slope break zone, and turbidite deposits are distributed in a fan-shaped pattern. The unique tectonic background and climatic conditions of the Late Triassic in the Ordos Basin, as well as strong orogenic activity, formed a gravity flow sedimentary model unique to this type of large depression lake basin. The sandy debris flow and turbid flow sand bodies are the first and second types of sand bodies of Chang 7 shale oil, respectively, and have currently formed economies of scale.

The lacustrine sediment of the Cretaceous Qingshankou Formation in the Songliao Basin is rich in organic shale, and the well Guye 1 has achieved a breakthrough in oil exploration of Gulong shale of deep lake facies. To further evaluate the geological characteristics of the shale sequence in different facies zones of the lacustrine basin and evaluate the characteristics of shale oil sweet spots in the continental lacustrine basin, we study the geological heterogeneity of shale sequences in different facies zones of the lacustrine basin regarding the environmental difference for lacustrine shale formation in the Qingshankou Formation. It is suggested that the shale sequences deposited in the freshwater lacustrine basin can be divided into seven types according to lithofacies, namely the organic-rich lamellar clayey shale (TOC > 3%), lamellar clayey shale, felsic shale, lamellar shell shale, massive mudstone, limestone and dolomite respectively, which are evaluated in terms of total hydrocarbon generated and retained, hydrocarbon mobility, reservoir property, compressibility and oil production capacity. The geological and engineering sweet spots of shale oil are thereby proposed. Based on the contents of TOC and S₁ (pyrolysis hydrocarbon content), we group the geological sweet spots of the Qingshankou Formation shale into Type Ⅰ, Ⅱ, and Ⅲ. The TypeⅠsweet spot is generally characterized by TOC content greater than 3% and S₁ greater than 4 mg/g; the Type Ⅱ by TOC content ranging between 1.5%and 3%, and S₁ between 1.0 and 4 mg/g; the Type Ⅲ by TOC content less than 1.5% and S₁ less than 1.0 mg/g. The semi-deep lacustrine and deep lacustrine facies are dominated by sweet spots of Type Ⅰ and Ⅱ, while the shales of shallow lacustrine facies by sweet spots of Type Ⅱ and Ⅲ. The Qingshankou Formation shale in Songliao Basin is selected as the major oil pay zone after a comprehensive analysis of the oil-bearing property, percolation coefficient, compressibility, characteristics of source rocks and physical properties of different facies zones.

China National Petroleum Corporation(CNPC)boasts abundant continental shale oil resources in areas covered by its mineral rights. The national hydrocarbon resource evaluation of the 13th Five-Year Plan reveals that CNPC’s geological resources of onshore moderately to highly mature shale oil(hereinafter referred to as shale oil)are estimated at 201×10⁸ tonnes, accounting for 71 % of the national total. Shale oil production has increased significantly in key plays such as the 7^th member of the Yanchang Formation in the Ordos Basin, the Qingshankou Formation in the Songliao Basin, and the Lucaogou Formation in the Junggar Basin, rising from 2.5×10⁴ tonnes in 2010 to 391.6 ×10⁴ tonnes in 2023, suggesting enormous potential for shale oil exploration. The study results reveal that CNPC’s commercial exploration of continental shale oil is facing challenges in both geological understanding and techniques due to the highly heterogeneous geological characteristics and significantly different factors determining the enrichment and high productivity across various types of continental shale oil reservoirs. Notably, despite large-scale exploration in the 1^st and 2^nd submembers of the 7^th member of the Yanchang Formation in the Ordos Basin, intercalated shale oilreservoirs exhibit greatly varying drilling ratio for targets under exploration, limited research on fine-grained sedimentary sequences of deep lacustrine facies, and the low accuracy of techniques for characterizing the spatial distribution of targets. Shale oil reservoirs of the mixed type exhibit great vertical thicknesses, frequent lithological variations, and multiple suites of sweet spots. Despite breakthroughs in the Qaidam and Bohai Bay basins, the exploration of these reservoirs is constrained by greatly different vertical shale oil production in geological sweet spots, ambiguous major factors contributing to high shale oil production, and imperfect techniques and methods for evaluating and selecting dominant targets. For the exploration of shale oil reservoirs of the pure shale type, breakthroughs have been achieved in the Gulong shale oil reservoirs of the Qingshankou Formation in the Songliao Basin. Nevertheless, due to greatly different hydrocarbon generation and expulsion characteristics and significantly varying in-situ hydrocarbon retention across various types of shales in continental lacustrine basins, it remains necessary to further investigate the geo-engineering integrated techniques and methods for target evaluation. Overall, CNPC’s exploration and exploitation of shale oil reservoirs are still rapidly advancing. In the future, it is necessary to intensify research on the genetic mechanisms of various sand bodies in deep parts of fresh lacustrine basins to achieve the commercial exploration of intercalated shale oil reservoirs such as thinly laminated turbidite sand bodies. For shale oil reservoirs of the mixed type, there is a need to enhance the evaluation of source rock-reservoir assemblages of these reservoirs enriched in carbonate in saline lacustrine basins. This will enable the preferential selection of primary targets for efficient exploration. Furthermore, differential evaluations of hydrocarbon generation and expulsion should be underlined for high-quality source rocks in both fresh and saline lacustrine basins to identify the optimal targets. The purpose is to achieve geo-engineering integrated, fine-scale exploration of shale oil reservoirs across various types of lacustrine basins.

The mineralogical development and diagenetic sequence of lacustrine shales in the Chang 7 Member of the Yanchang Formation in the Ordos Basin are detailed studied. A model of their depositional system and a diagenetic diagram are proposed in this study. Through detailed petrographic, mineralogical, and elemental analyses, four distinct shale types are identified: argillaceous shale, siliceous shale, calcareous shale, and carbonate, clay, and silt-bearing shale. The main diagenetic process in argillaceous shale is the transformation of illite to smectite, negatively impacting shale porosity. Siliceous shale undergoes carbonate cementation and quartz dissolution, contributing to increased porosity, particularly in mesopores. Calcareous shale experiences diagenesis characterised by carbonate formation and dissolution, with a prevalence of siderite. In carbonate, clay, and silt-bearing shale, the dissolution of K-feldspar contributes to illitization of kaolinite. Argillaceous shale, characterised by more clay minerals and lower mesopore volume, is identified as a potential hydrocarbon seal. Siliceous shale, with the highest pore volume and abundant inter-mineral pores, emerges as a promising shale oil reservoir. These findings contribute to a comprehensive understanding of shale properties, aiding in the prediction of shale oil exploration potential in the studied area.