Shale gas in southern China is found to contain economically valuable helium (He), which is inconsistent with conventional perspective that hydrocarbon gases in shale would dilute He to sub-economic levels. The adsorption of gases in the nanopores of organic matter is considered a crucial factor influencing the shale gas composition. The adsorption behaviors of He, methane (CH₄) and their mixtures in kerogen nanopores were performed by the Grand Canonical Monte Carlo simulation. The molecular simulations of pure He reveal that He can be adsorbed in shale and the adsorption capacity of He increases with the burial depth of shale. Before the hydrocarbon generation from kerogen, He has been continually generated in shale, the simulations further demonstrate that pure He can be partially preserved in shale as adsorbed gas phase. The simulations of competitive adsorption between CH₄ and He show that the adsorption selectivity of CH₄/He is consistently higher than 1.0 under the simulated conditions. This indicates that the previously adsorbed He will be displaced by CH₄ and subsequently concentrated in hydrocarbon gas as free gas phase during the process of hydrocarbon gas generation from kerogen. After the termination of hydrocarbon gas generation, He continues to be generated in shale and preferentially concentrated in free shale gas. Therefore, the concentration of He in shale gas will gradually increase with the generation time of He. In addition, our simulations indicate that high pressure and deep burial depth can enhance the adsorption of He in kerogen, suggesting that deeply buried organic-rich shale probably retains more adsorbed helium. Molecular simulations of He adsorption provide new insights into the accumulation process of He in shale gas and are of great significance for assessing helium resource potential in shale gas.

Nitrogen isotope compositions (δ¹⁵N) of sedimentary rocks are usually used to reconstruct the paleoenvironment and nitrogen (N) biogeochemical cycle. The δ¹⁵N values of crude oils inherit the characteristics of relevant source rocks and can well reflect the information of hydrocarbon-forming organisms and environment in ancient water column. However, studies on the δ¹⁵N of crude oils are limited due to the low N content. In this study, a new efficient method is applied to the marine oils from the Bashituo (BST) and Halahatang (HLHT) areas of the Tarim Basin to obtain the nitrogenous components (i.e., nonhydrocarbons and asphaltenes) for the achievement of N concentration. The carbon and nitrogen isotopes of these components and the biomarkers of oils were measured. The δ¹⁵N values in asphaltenes (δ¹⁵N_Asp) are significantly heavier than those in nonhydrocarbons (δ¹⁵N_NSOs) in these oils, which are attributed to the potential directional N transfer and kinetic isotope fractionation during the thermal evolution of organic matters (OM). The δ¹⁵N_Asp values have significant correlations with OM origin associated parameters and weak correlations with environmental parameters, suggesting that the difference in δ¹⁵N_Asp values is mainly resulted from biological source rather than redox conditions. The δ¹⁵N_NSOs values have a closer relationship with the redox condition than biological characteristics, indicating that they have a good response to paleoenvironmental variation in the water column, which is not completely overprinted by the difference of OM origin. Different redox conditions give rise to distinct nitrogen cycles, resulting in various δ¹⁵N values. Anammox occurs in the water column of the Early Cambrian dominated by physically stratified conditions with significant isotope fractionation, resulting in relatively heavier δ¹⁵N of OM in the BST area. In the Middle–Late Ordovician period, the limited suboxic zone leads to an insignificant positive bias of δ¹⁵N caused by partial denitrification in the HLHT oils. The evaluation of δ¹⁵N in nitrogenous fractions enables a more comprehensive reconstruction of N cycle for ancient oceans.

The Dongying Depression is an important petrolifeous province, with diverse source rocks and complex petroleum distribution patterns. A total of 32 crude oils were analyzed by the gas chromatography–mass spectrometry and isotopic compositions to better understanding the petroleum systems in the study area. Three oil types were classified by hierarchical cluster analyses. Type Ⅰ and Ⅱ oils have closely correlation with the discovered source rocks, which have been confirmed to be mainly derived from the lower third and upper forth member of the Eocene Shahejie Formation source rocks (Es3^L and Es4^U), respectively. Obviously, type Ⅲ oils contain abundant gammacerane, tricyclic terpanes and C₂₉ steranes and have lower values of δ¹³C than type Ⅰ and Ⅱ oils, indicating a completely different source rock and biological origins. Until recently, type Ⅲ oils fail to match any of the discovered source rock, which contains main contribution of aquatic organism or/and bacteria inputs. In addition, the spacial distribution of these three oil types were discussed. Type Ⅰ oils mainly distributed in the Es3 and Es4 reservoirs that closed to the generative kitchens. Type Ⅱ oils occurred in the Es4 reservoirs in the sourthern slope of the depression, which probably caused by lateral migration along the horizontal fractures and sandstone layers within the Es4 interval. Differently, type Ⅲ oils in the sourthern slope of the depression were mainly discovered in the Eocene Kongdian or Ordocician reservoirs, which suggests great exploration potential of deep underlying strata.