The tectonic background and sedimentary environment during the transition period from the Ordovician to Silurian have been widely studied by many scholars. This study focuses on the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation in the Bajiaokou profile at the southern margin of the Qinling Orogenic Belt in southern China. In order to study the aggregation mechanism of organic matter, geochemical proxies were proposed, including redox proxies (V, V/Al, U, U/Al, Mo, and Mo/Al), paleoproductivity proxies (P, P/Ti, Ba, Ba/Al, and Si_XS), paleoclimate proxies (CIA), and terrigenous flux proxies (Al, Zr, and Zr/Al). In addition, Al-Co[EF] × Mn[EF] is used to provide information on paleoenvironmental parameters such as watermass restriction conditions. The redox proxies show that the Wufeng-Longmaxi shale is mainly accumulated under oxic-dysoxic conditions. During the shale deposition period of Wufeng-Longmaxi formations, the marine surface primary productivity in the southern Qinling area is generally low to moderate. The paleoclimate proxies show that from the Late Ordovician to the Early Silurian the southern Qinling area generally had a warm and humid climate. The upwelling current is widely developed in the northern margin of the Sichuan Basin and the southern margin of the Qinling area. Although the upwelling current was highly developed during the deposition of the Wufeng Formation in the Bajiaokou profile, the concentrated accumulation of a large amount of volcanic ash resulted in the low primary productivity of the ocean. During the sedimentary period of the Longmaxi Formation in the Bajiaokou profile, the development of seasonal upwelling currents and a small amount of volcanic ash supply increased the primary productivity to moderate, which provided a good material basis for the enrichment of organic matter, but the high detritus flux and the water body condition of oxic-dysoxic resulted in the slight enrichment of organic matter.

The reservoir properties of low–medium-maturity shale undergo complex changes during the in situ conversion process (ICP). The experiments were performed at high temperature (up to 450 °C), high pressure (30 MPa), and a low heating rate (0.4 °C/h) on low–medium-maturity shale samples of the Chang 7 Member shale in the southern Ordos Basin. The changes in the shale composition, pore structure, and reservoir properties during the ICP were quantitatively characterized by X-ray diffraction (XRD), microscopic observation, vitrinite reflectance (Ro), scanning electron microscopy (SEM), and reservoir physical property measurements. The results showed that a sharp change occurred in mineral and maceral composition, pore structure, porosity, and permeability at a temperature threshold of 350 °C. In the case of a temperature > 350 °C, pyrite, K-feldspar, ankerite, and siderite were almost completely decomposed, and organic matter (OM) was cracked into large quantities of oil and gas. Furthermore, a three-scale millimeter–micrometer–nanometer pore–fracture network was formed along the shale bedding, between OM and mineral particles and within OM, respectively. During the ICP, porosity and permeability showed a substantial improvement, with porosity increasing by approximately 10-times and permeability by 2- to 4-orders of magnitude. Kerogen pyrolysis, clay–mineral transformation, unstable mineral dissolution, and thermal stress were the main mechanisms for the substantial improvement in the reservoir’s physical properties. This study is expected to provide a basis for formulating a heating procedure and constructing a numerical model of reservoir properties for the ICP field pilot in the Chang 7 shale of the Ordos Basin.

In-situ conversion technology is a sustainable and effective method of recovering medium-low maturity shale, which can be produced with oil resources expected to exceed global total proven oil reserves. Nevertheless, criteria and procedures for grading such shale oil resources are lacking. We present a combination of distinct faceis and theoretical economic index (I_e) to grade the in-situ conversion shale oil resources of Chang 7 Member in the Ordos Basin and Nenjiang Formation in the Songliao Basin. This shale oil resource was categorized into four classes: invalid, valid, sweet-spot and core resource. For the shale dominated by type II kerogen (Chang 7), total organic carbon (TOC) values at 6%, 9%, and 12%, hydrocarbon generation potential (S₁+S₂) values at 15 mg/g, 30 mg/g, and 50 mg/g, and I_e at 2, 3, and 4, respectively, represent the boundary of the four resource grades. For the shale dominated by type Ⅰ kerogen (Nenjiang), TOC values at 4%, 6%, and 8%, S₁+S₂ values at 19 mg/g, 32 mg/g, 48 mg/g, and I_e at 2, 3, and 4, respectively, represent the boundary of the four resource grades. Our research provides a feasible practical strategy for evaluating and predicting in-situ conversion shale oil resources in lacustrine basins.

The Jimsar Sag is an important shale oil exploration target area in the Junggar Basin, northwestern China. The Permian Lucaogou Formation, with a thickness of 200–300 m, is the primary exploration target. High-frequency variation in lithology is a typical feature of the Lucaogou Formation, reflecting the fluctuation of the depositional environment and organic matter enrichment. The evolution of the depositional environment and accumulation mechanism of organic matter still need to be elucidated for the Lucaogou Formation. High-resolution sampling of the entire Lucaogou Formation was applied to a 248 m long core from Well JX in the Jimsar Sag to examine the depositional environment and organic matter enrichment. The findings unveiled that the Lucaogou Formation was deposited under a hot and arid climate, within the confines of a closed saline paleo-lake, where sediments endured an extended period of anoxic conditions, displayed periodic oscillations in paleo-temperature and paleo-salinity values over time, alongside a continuous rise in paleo-water depth. The predominant source lithology of the Lucaogou Formation is felsic igneous rock. Small-scale transgression and hydrothermal sedimentation occurred during the deposition of the Lucaogou Formation. The prevailing hot climate and enduring reducing environment fostered ideal circumstances for the enrichment of organic matter in the Lucaogou Formation. Due to different sedimentary environments and enrichment mechanisms, organic matter is enriched in two modes in the Lucaogou Formation.

Previous studies have mainly focused on the source rocks of the 7th Member of Yanchang Formation (Chang 7 Member) in the Ordos Basin, with very few studies focusing on the extracts from the source rocks. These extracts have important guiding significance for studying the in situ conversion process of shale oil. Taking the shale source rock of the Chang 7 Member as an example, this paper selected the extract of shale source rock (i.e., retained oil), which has been less studied previously, as the sample to carry out the hydrocarbon-generating pyrolysis simulation experiment of a semi-open–semi-closed system. Seven groups of parallel simulation experiments were designed with a pressure of 20 MPa. The generated oil and gas were collected and quantified, and their geochemical characteristics were researched. In addition, the generated oil and gas were investigated from aspects of cumulative yield and net increased yield, and the chromatographic and mass spectral characteristics of the generated oil were also researched. Based on this, an inductive hydrocarbon generation model of retained oil in shale source rocks was established: slow hydrocarbon generation stage (300–320 °C), rapid hydrocarbon generation stage (320–360 °C), and residual oil pyrolysis stage (0.79%Ro–1.47%Ro). This study is of important significance to guide the research on the in situ conversion process of shale source rock.

Deep insights into the movability of the retained shale oil are of great significance to shale oil. Rock and crude oil samples were collected from well J174 in the Jimsar Sag, Junggar Basin. Rock samples were subjected to different extraction followed by analysis of the component in the extracts, and measurement of porosity in conjunction with nuclear magnetic resonance and high-pressure mercury injection analysis. The results of these analyses were used to establish an experimental method for quantitative assessment of movable shale oil. The extract content of the component varied among different extraction and between mud shale and non-mud shale samples. The saturated hydrocarbon in the extracts of the mud shale was similar to those of the non-mud shale after extraction with CHCl₃ alone or after sequential extraction with nC₆ + CHCl₃. The aromatic hydrocarbon in the extract were significantly lower for the mud shale than for the non-mud shale after extraction with nC₆, but the opposite was observed after sequential extraction with nC₆ + CHCl₃. The contents of the non-hydrocarbon in the extract were significantly lower for the mud shale than for the non-mud shale after extraction with nC₆, but the opposite was observed after extraction with CHCl₃ or nC₆ + CHCl₃. The contents of the asphaltene in the extract were not significantly different for the mud shale and non-mud shale after extraction with nC₆, but the contents were higher for the mud shale than for the non-mud shale after extraction with nC₆ + CHCl₃ or CHCl₃. The viscosity of the crude oil was negatively correlated with the saturated hydrocarbon, was positively correlated with the aromatic hydrocarbon and non-hydrocarbon, and was not correlated with the asphaltene. For the mud shale and non-mud shale, their porosity after extraction with nC₆ or CHCl₃ was higher than their original porosity. Moreover, their porosity after extraction with CHCl₃ was higher than after extraction with nC₆. The movable oil was significantly correlated with the lithology, with sandstone allowing for a higher fluid movability than mud shale and dolomite allowing for a higher fluid movability than siliceous rocks.