Junqing Chen

Quantifying the relative contributions of multiple source rock intervals remains a major challenge for petroleum exploration in superimposed basins. In the southwestern Tarim Basin (SWTB), the respective contributions of the Carboniferous, Permian and Jurassic source rocks have long been debated. This study integrates geological and geochemical data, burial‐thermal history reconstruction and hydrocarbon generation‐expulsion modelling based on the Hydrocarbon Generation Potential (HGP) method to quantitatively evaluate the hydrocarbon contributions of the three source rock intervals. The results reveal significant differences in expulsion efficiency. Carboniferous source rocks (Type II–III kerogen, average TOC 0.36%) generated 28.63 Gt of hydrocarbons and expelled 25.29 Gt, with an expulsion efficiency of 88.3%, accounting for 70.7% of total expelled hydrocarbons. Permian source rocks (Type II ₂ –III kerogen, average TOC 1.3%) generated 27.47 Gt but expelled only 9.78 Gt (35.6% efficiency, 27.3% of total expulsion). Jurassic source rocks (Type II ₂ –III kerogen, average TOC 2.19%) generated 8.09 Gt but expelled only 0.70 Gt (2.0% of total expulsion). The Carboniferous is therefore identified as the dominant contributor, the Permian as secondary and the Jurassic as minor. These differences are primarily controlled by organic matter type, thermal evolution history and reservoir‐caprock configuration. Hydrocarbon generation‐expulsion centres are concentrated in the Kashi Sag and the Kekeya‐Fusha area, where hydrocarbons migrated predominantly along strike‐slip fault systems, forming a near‐source vertical accumulation pattern. The results demonstrate that hydrocarbon contribution is controlled not only by hydrocarbon generation potential but also by hydrocarbon expulsion efficiency, providing a quantitative basis for identifying dominant source rocks and evaluating multi‐source petroleum systems in complex superimposed basins.

In recent decades, with the advancement of detection technologies, the exploration and development of deep carbonate reservoirs worldwide have progressed continuously, the number of oil and gas reservoirs has continued to increase. Compared with sandstone reservoirs, the enrichment patterns of carbonate reservoirs are substantially more complex. In recent years, petroleum geologists have deepened their understanding of capillary pressure due to the continuous expansion of reservoir formation research, supplemented by new methods and techniques. Numerous scholars have begun to focus on the positive impact of capillary pressure on hydrocarbon migration and accumulation. Determining the variation in capillary pressure in carbonate rocks with burial depth is of considerable importance for understanding the mechanisms of oil and gas enrichment. In this study, molecular dynamics simulations were used to determine the relationship between oil–water interfacial tension and depth variation in carbonate reservoirs. The data obtained from previous experiments were then used to obtain changes in contact angle and pore-throat radius with depth. Finally, a new model for capillary pressure variations with depth in carbonate reservoirs is derived based on interface tension, contact angle, and pore-throat radius. The results indicate that the interfacial tension of carbonate rocks decreases with increasing burial depth. The contact angle decreases with increasing temperature and increases with increasing pressure. The variation of capillary pressure with burial depth is related to porosity, permeability, and depth. The new model developed in this study is beneficial for understanding the formation mechanisms of carbonate reservoirs, providing guidelines for oil exploration and development in deep or even ultradeep carbonate reservoirs.

The complex transport behavior of hydrocarbons in micro/nanochannels leads to inaccuracies in identifying hydrocarbon accumulation zones, as well as to hydrocarbon leakage. Hydrocarbon movement through confined channels is difficult to characterize and understand in detail because it involves complex hydrodynamic behaviors of hydrocarbon under the joint effects of various physical and chemical effects. Microfluidic platforms provide a powerful means to directly visualize and quantify these confined transport behaviors. In this work, we summarize recent theoretical and experimental advances enabled by microfluidic approaches and highlight five dominant mechanisms governing hydrocarbon transport in micro/nanochannels: (1) molecular sieving and adsorption jointly control the lower transport limit; (2) asphaltene aggregation induces pore blockage; (3) wall slip triggers ultrafast flow; (4) strong confinement shifts the hydrocarbon phase envelope; (5) wettability and roughness modulate capillary retention and flow resistance. Integrating these insights into reservoir simulation frameworks will improve the accuracy of hydrocarbon flow prediction.

Shale oil and gas, as an essential type of unconventional oil and gas resources, and compressibility is one of the most critical aspects of shale oil and gas exploration and development. Elastic parameters have a significant impact on the compressibility of shale. Montmorillonite is one of the typical clay minerals in shale, and its microstructure has unique characteristics. When encountering water underground, it is effortless to expand. Therefore, the study of the mechanical properties of montmorillonite is crucial. This study is based on molecular dynamics simulation to establish Na‐montmorillonite with different hydration degrees, change its temperature and pressure, conduct comprehensive research and comparison by combining the elasticity parameter of montmorillonite with different hydration degrees, and explain the micro mechanism of its impact. Simulation results display that the mechanical properties of hydrated montmorillonite are negatively correlated with temperature. There is a positive correlation with pressure. As the degree of hydration increases, the mechanical properties of montmorillonite decrease. The mechanical properties of montmorillonite are anisotropic. The factors that play a leading role in the stage of temperature, pressure and hydration degree under micro and macro conditions are studied. This research achievement has guiding significance for the comprehensive understanding of montmorillonite and the elastic parameters of shale at the micro level.

The source of oil and gas in the Tarim Basin's platform has always been controversial. The Lower Cambrian Yurtusi Formation and the Xidashan Formation–Xishanbulak Formation argillaceous source rocks are an important set of oil source series in the basin. Based on the principle of conservation of matter, this paper calculates the hydrocarbon expulsion amount of the source rock. Using a phase state hydrocarbon expulsion amount characterization model, the paper reconstructs the evolution process of the hydrocarbon expulsion phase state of the source rock. According to the characterization model of hydrocarbon expulsion dynamics, the relative contribution of each force to hydrocarbon expulsion is evaluated. The hydrocarbon expulsion geologic model of argillaceous source rocks in the Lower Cambrian in the Tarim Basin is established. The results show that this set of source rocks can serve the main source rocks in the basin. The hydrocarbon expulsion of the Lower Cambrian argillaceous source rocks in the Tarim Basin can be divided into three stages. In the first stage, the hydrocarbon expulsion phase is dominated by the water‐soluble and diffusion phases. The conversion of clay minerals into dehydration and diffusion forces is the main driving force for the hydrocarbon expulsion. In the second stage, the oil and gas expulsion present the characteristics of multiphase and multidynamic coexistence. In the third stage, the phase state of oil and gas expulsion is mainly free phase. The capillary force difference and the thermal expansion force of the fluid rock are the main driving forces for oil and gas expulsion. The research results of this paper can deepen the understanding of the hydrocarbon expulsion mechanism of the set of source rocks, and then guide oil and gas exploration.

Nanoscale pores are an important storage space in shale petroleum reservoirs. Mineral surface wettability significantly affects the adsorption ability of a fluid, and it is of great significance for the efficient development of shale petroleum. Within a nanoscale pore, however, we cannot measure the contact angle through a conventional measuring method, so we used a molecular dynamics (MD) simulation method. A nanoscale ‘oil–water–rock’ wettability model was used to study the wettability of reservoir minerals with micropores. In this study, by means of MD simulation, the wettability models of different minerals (calcite, quartz and illite) and different liquid hydrocarbons (n‐hexane, toluene and acetic acid) were established, and then the temperature and pressure were changed to study the influence of mineral type, liquid hydrocarbon type, temperature and pressure on wettability. The results show that calcite has the strongest wettability of water in n‐hexane, followed by illite and quartz, and toluene has the strongest wettability of water on the surface of calcite minerals, followed by n‐hexane and acetic acid. In the temperature range of 313–378 K, the higher the temperature, the stronger the water wettability. In the pressure range of 5–20 MPa, the higher the pressure, the water wettability is stronger. By comparing the MD simulation results with the previous experimental results, similar wetting characteristics were obtained, which verified the reliability of the simulation results. This MD simulation method provides a new idea for the study of shale mineral wettability, which is of great significance for shale petroleum exploration.

In recent years, a large amount of industrial oil and gas resources have been discovered in the Paleogene Wenchang Formation (WC) of the southern Lufeng sag, confirming that the WC resources are promising prospects for petroleum exploration. However, because of the complex lithology, multiple sources of crude oil and multi-period charging characteristics in the WC, the accumulation process and model have not been clearly understood. Therefore, in this study, the main sources of crude oil and the process of hydrocarbon accumulation in key oil accumulation periods are determined by combining biomarker and geological analyses. Finally, the model of oil and gas accumulation is systematically summarized. The obtained results show that the source rock of the WC is the main source of hydrocarbons in the study area. The crude oil types in the southern Lufeng sag are classified into three types. Type A crude oil comes from source rocks of Wenchang Formation Members 3 and 4. Type B crude oil comes partly from source rocks of Wenchang Formation Members 1, 2, and 3 and partly from source rocks of Wenchang Formation Members 5 and 6. Type C crude oil is a mix of type A and type B crude oil. There are three accumulation periods that typify the study area: in the first period, accumulation was with vertical migration by fault; in the second period, accumulation was with lateral migration by sand body; and in the third period, accumulation was with vertical migration by sand body and adjacent to the source. The methodology and results of the accumulation process in southern Lufeng sag can support offshore oil and gas exploration.