The Paleogene strata in the southwestern Huizhou Sag of the Pearl River Mouth Basin (PRMB) are characterized by a high sand content and the predominance of fault traps, where hydrocarbon accumulation is closely related to the lateral sealing capacity of faults. Drilling data reveal that in parts more adjacent to fault zones, reservoirs feature more developed calcareous cements within sandstones. However, the impact of cementation on the lateral sealing capacity of faults in the southwestern Huizhou Sag remains poorly understood. By integrating multiple techniques, including carbon and oxygen isotope analysis, cathodoluminescence, homogenization temperature measurements of fluid inclusions, and clumped isotope thermometry, we reveal the genetic mechanisms of calcareous cements within fault zones and clarify their role in modifying the seepage properties of the fault zones. Accordingly, a comprehensive evaluation index (F_lcs) is developed to evaluate the lateral sealing capacity of trap-bounding faults. The research findings indicate that the formation of calcareous cements resulted from a combination of basement-derived hydrothermal fluids and the decarboxylation of sedimentary organic matter, as suggested by their carbon and oxygen isotope compositions. Specifically, these cements were formed in a weakly reducing to reducing environment, and their formation period (postdating the deposition of the Yuehai Formation) is roughly consistent with the hydrocarbon charging periods. Governed by the vertical differences in the thermal maturity of sedimentary organic matter, cementation within fault zones exhibits a distinct zonation. In zones with intense cementation, calcareous cements effectively block the fluid seepage pathways within fault zones, whose permeability decreases significantly with increasing cement content. Index F_lcs is established by comprehensively considering the dual impacts of compaction and cementation on the seepage mechanisms of faults while combining fault-reservoir displacement pressure differences and cement zones determined by vitrinite reflectance (R_o). Validation confirms high consistency between Flcs-based sealing evaluations and actual hydrocarbon-water distributions. Notably, F_lcs values exceeding 0.4 suggest effective hydrocarbon sealing capacity.

Wells encountering the Miocene marine source rocks in the Yinggehai Basin are mostly confined to the edge and slope areas, leaving the overall forming environment and distribution of these high-quality source rocks in the basin a puzzle to be cracked. This paper, from the perspective of biogeochemistry and environmental geochemistry, reveals the main controlling factors of the formation and distribution of the source rocks through a systematical analysis of paleoproductivity, terrestrial organic matter input and redox conditions of the rocks in the basin. The P/Ti values of the source rocks indicate relatively low paleo-productivity, with only that of the Ledong area showing an increasing trend. The supply of terrestrial organic matter is relatively sufficient because of several rivers around the basin. Oleanane derived from angiosperms is widely occurring in the source rocks, especially those in the Sanya Formation. The Ni/Co ratios of the rocks from the Yingbei, Yingdong Slope, Dongfang and Ledong areas indicate an oxic environment with the redox conditions in the Ledong area better than the rest. The relationship between TOC values and P/Ti and Ni/Co ratios shows that the paleo-productivity and redox conditions only control the formation of the source rocks from L30-1 wellblock in the Ledong area. TOC values of the source rocks have a positive correlation with the oleanane index (oleanane/C₃₀ hopane), showing that terrestrial organic matter input has a significant control effect on the development of marine source rocks. The H29-1 wellblock of the Yingbei area, provided with sufficient supply of terrestrial organic matter from both Hainan Island and the Red River, serves as a perfect location for enrichment of high orgnic marine source rocks. While the D29-2 and L30-1 wellblocks with fine paleo-productivity and redox conditions are relatively good for the formation of endogenous high-quality source rocks.

Deep mixed oils with secondary alterations have been widely discovered in the Tarim Basin, but current methods based on biomarkers and isotopes to de-convolute mixed oil cannot calculate the exact mixing proportion of different end-member oils, which has seriously hindered further exploration of deep hydrocarbons in the study area. To solve this problem, we constructed a novel method based on the carbon isotope (δ¹³C) of the group components to de-convolute mixed liquid hydrocarbons under the material balance principle. The results showed that the mixed oil in the Tazhong Uplift was dominantly contributed at an average proportion of 68% by an oil end-member with heavier δ¹³C that was believed to be generated from the Cambrian-Lower Ordovician source rocks, whereas the mixed oil in the Tabei Uplift was predominantly contributed at an average proportion of 61% by an oil end-member with lighter δ¹³C that was believed to be generated from the Middle-Upper Ordovician source rocks. This indicates that, on the basis of the detailed description of the distribution of effective source rocks, the proposed method will be helpful in realizing differential exploration and further improving the efficiency of deep liquid hydrocarbon exploration in the Tarim Basin. In addition, compared to traditional δ¹³C methods for whole oil and individual n-alkanes in de-convoluted mixed oil, the proposed method has a wider range of applications, including for mixed oils with variations in color and density, indicating potential for promoting the exploration of deep complex mixed oils in the Tarim Basin and even around the world.