The Permian Lucaogou Formation of the Jimsar Sag in the Junggar Basin, NW China, is one of the largest areas of oil exploration and exploitation in the lacustrine shale sequence in China. Oil is commercially extracted from this markedly heterogeneous formation, which is characterized by frequently interbedded shale and tight reservoirs, although producible intervals within the Lucaogou Formation remain unresolved. This study focused on the Jimsar Sag reservoirs to investigate petrological and mineralogical characteristics, source rock and reservoir physical properties, and the molecular biogeochemistry of core extracts and crude oils. The i-C₁₈/n-C₁₈ and Pr/n-C₁₉ ratios of two-step ultrasonic extracts were applied to infer whether the oil is produced from shale or tight reservoirs, taking into account solvent polarity, molecular characteristics of n-alkanes and isoprenoids, and physical properties of the reservoir. The experimental results indicated that the shallower pay zone is mainly produced from tight reservoirs, while in deeper zone with organic-matter maturity above 1.0%, some of the oil is produced from shale. The reservoir properties in organic-rich shale with vitrinite reflectance (Ro) exceeding 1.0% are improved by pore interconnectivity, and oil mobility is enhanced by high gas/oil ratios, which favors production of free-phase hydrocarbons. Such zones may become major prospects for shale oil exploration and production. The results of the present study can potentially apply to sweet-spot identification and development optimization for the Lucaogou shale and other lacustrine shale sequences.

To better understand oil and gas generation and expulsion mechanisms and their controlling factors, two-stage heating program (20 and 5 °C/d) at 11 target temperatures (250–580 °C) have been performed in a semi-open reactor on nine immature lacustrine shale samples from the Triassic Yanchang Formation in Ordos Basin, NW China, with total organic carbon (TOC) contents ranging from 0.5% to 30.0%. The cumulative expelled oil and gas were quantified and correlated with the measured vitrinite reflectance (%R_o) and residual TOC. The amount of expelled oil increases substantially with increasing maturity in the R_o range of 0.5–1.25% and ends at R_o of >1.45%, while the volume of expelled gas increases markedly with maturity when R_o is >1.0%. Organic richness exerts primary control on the expulsion yields, which increase linearly with increasing original TOC (TOC_o) per unit weight of rock, whereas the increment decreases with TOC_o per unit weight of TOC, once the TOC_o content is above 5%. Marked TOC reduction occurs in the R_o of 0.5–1.1% due to oil generation and expulsion, but the trend is reversed in the higher maturity range possibly caused by the simultaneous decomposition of minerals. Numerical correlations among heating temperatures, %R_o, TOC content, and expelled oil and gas yields have been constructed, and the minimum TOC contents for effective oil and gas source rocks have been inferred. The lowest TOC contents of 0.5% and 0.48% are required for oil and gas expulsion in the oil and gas generation window, corresponding to the TOC_o of 0.91% and 0.76%, respectively. The minimum TOC content for effective gas source rocks decreases slightly with increasing maturity; however, a much higher TOC cutoff is required for lower maturity level source rocks. Wide range of TOC content variation in our studied samples provides well constraint of organic richness on oil and gas generation and expulsion behaviors and their evolution trajectory during thermal evolution, which will fascinate source rock quality and exploration potential assessment in other source rock systems.

Shale is of strong heterogeneity. The mineral composition has a significant influence on the diagenetic evolution, pore network formation, hydrocarbon content, oil mobility, and reservoir stimulation of shale. Accurate mineral analysis of shale is an essential precondition for scientific research and industrial production. In this study, we present a new quantitative method for shale mineral analysis based on high-resolution images, using a combination of QEMSCAN and MAPS technology. We overcome the problem of errors between the morphology and content of certain minerals identified by QEMSCAN technology and the actual results and take full advantage of high-resolution large-scale backscatter scanning electron microscopy (MAPS technology) to process clay-grade mineral image data with complex contact relationships. Specifically, we realize the correction of QEMSCAN mineral quantitative analysis results through image smoothing, image alignment, image segmentation, morphological analysis, and other image processing technologies. The method enables the precise and fast measurement of mineral types, contents, and two-dimensional (2D) distributions. It provides a more credible result consistent with geological reality than QEMSCAN. A straightforward application of the new method is refined mineralogical analysis, including the characterization of pores, fractures, organic matter, and/or mineral grains in geological materials.

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.

This study proposes a method to calculate the retained oil content (W_O) in cores collected by a sealed tool from organic-rich shale with thermal maturity around%Ro = 0.8 in the Ordos Basin, China. Approaches such as soaking cores at low temperature, multiple extractions, multiple pyrolysis, and multiple chromatographic analyses were conducted and then the relationships between total retained oil content and mineral compositions were analyzed. The total retained oil content measured by the method proposed in this paper is 60–260% higher than that measured by a conventional pyrolysis method and 34–69% higher than the sum (W_O) of two extractions with dichloromethane (W_O3) and chloroform (W_O4). After extractions with dichloromethane and chloroform (W_O5), the oil retained in the organic-rich shale was 4.7–11.6%, which has not been extracted. Positive correlations exist between W_O (i.e., W_O3 + W_O4) and total organic carbon (TOC) and S₁ (absorbed hydrocarbon by rock pyrolysis), and W_O has the highest correlation coefficient with the former. The method can provide important guidance for the objective analysis of retained oil in organic-rich shale, and it is reliable for the evaluation of shale oil reserves.