Rock-Eval pyrolysis has been widely used in assessing source rocks from the very beginning. Although this approach can evaluate oil content, hydrocarbon generation, as well as the abundance, type, and thermal maturity of organic matter in a simple and rapid way, it is noteworthy that this technique has some limitations in application, and improper interpretation of pyrolytic data may bring more risks to shale oil/gas exploration. This study summarizes three main pitfalls commonly seen in previous publications based on massive experimental results. First, the use of hydrogen index (HI), oxygen index (OI), the temperature of maximum pyrolysis yields (T_max), and the ratio of S₂/S₃ to discriminate kerogen of diverse types should target source rocks with maturity less than 1.35 % R_o; the feasibility of the technique to highly-to-overmature source rock samples is limited. Second, the validity of T_max depends on the area of S₂ and whether it is in normal distribution, and the accuracy of T_max relies on kerogen type and thermal maturity; moreover, residual hydrocarbon and pyrite content have some effects on the accuracy of T_max. To obtain accurate T_max values, the maturity of source rocks of types Ⅰ, Ⅱ, and Ⅲ should not be larger than 1.70 % R_o. Third, the oil saturation index (OSI) has been used to indicate the mobility of shale oil, and a value larger than 100 mg/g TOC suggests sweet spots of shale oil. However, it should be noted that OSI could not directly provide information on the saturation of oil in shale. OSI values are generally smaller than 100 if the rocks are very organic-rich, and a small TOC value could also lead to a large OSI value (more than 100 mg HC/g TOC). Besides, only a few shales bear OSI higher than 100 mg HC/g TOC, although many of the shales have been proven commercially successful. Therefore, the applicability of OSI larger than 100 mg HC/g TOC as a parameter for shale oil mobility merits further consideration. We suggest using individual OSI criteria for different types of sedimentary basins and shale formations. Moreover, the loss of light hydrocarbons during the storage and preparation of rock samples is strongly dependent on rock lithofacies, and thus, classified assessment should be adopted for shale oil reservoirs of multiple lithofacies.

Research has identified and increasingly explored the micro-migration phenomenon in shaly strata, which is currently one of the key scientific issues affecting shale oil accumulation and efficient development. Recently, qualitative and quantitative methods for characterizing hydrocarbon fractionation related to shale oil micro-migration have been proposed, which brought promising prospects to oil micro-migration research. Three key techniques in this field are summarized in this minireview, and the outlook for shale oil micro-migration characterization is prospected. Fourier transform ion cyclotron resonance mass spectrometry can be employed to distinguish subtle composition differences related to short-distance migration; core-flooding extraction experiments can be utilized for the quantitative characterization of micro-migration in organic-rich shale; and semi-open thermal simulation experiments are useful to analyze the chemical composition and structural evolution of expelled and retained oil. These three methods have different focus and advantages, while they provide different viewpoints and means for the characterization of shale oil micro-migration and have all achieved good results in different regions. Studies regarding the latest technologies deepen our understanding of the short-distance migration of shale oil, as well as improve our knowledge of the mechanisms of shale oil micro-migration, which is of great practical significance to the evaluation of shale oil content and mobility and further optimizes the identification of sweet spots and the effects of fracturing development.