The mechanisms underlying the self-sealing accumulation of unconventional hydrocarbons form the core of the whole petroleum system (WPS) theory. Forces driving the self-sealing process originate from intermolecular interactions, and their manifestations and mechanisms vary with reservoir media and geological conditions. In this study, a series of results and insights are obtained through systematic investigation. Essentially, the self-sealing accumulation of unconventional hydrocarbons is a non-buoyancy process dominated by intermolecular interactions. For the first time, three major mechanisms behind the self-sealing accumulation are systematically identified: interfacial effect, confinement effect, and steric hindrance effect. The principles and scaling effects of these mechanisms are accordingly defined. Factors influencing the forces that drive the self-sealing of various unconventional hydrocarbon resources are determined. Specifically, the self-sealing of tight hydrocarbons and free shale hydrocarbons is predominantly driven by capillary pressure at megapascal (MPa) level, governed by the pore size, interfacial tension, and wettability of reservoirs. In contrast, the self-sealing of adsorbed shale hydrocarbons and coalbed methane (CBM) is primarily driven by molecular adsorption forces under the confinement effect, with the adsorption energy jointly influenced by mineral surface properties, pore structure, temperature and pressure conditions, and fluid characteristics. Models describing self-sealing governed by the relative sizes of pores and hydrocarbon molecules are established. These models reveal that under ultra-tight pores, where pore sizes are comparable to molecular sizes, the steric hinderance effect predominates, causing mechanical obstruction for large molecules. When pore sizes are less than 38 times molecular sizes, differential adsorption of hydrocarbons becomes significant, leading to the gradual emergence of the confinement effect. Conversely, when pore sizes are far larger than molecular sizes, self-sealing is primarily driven by the interfacial effect. This study presents a systematic elucidation of various types of intermolecular interactions involved in the self-sealing of unconventional hydrocarbons, along with methods for their quantitative characterization. The results of this study deepen the understanding of the mechanisms governing the self-sealing accumulation and offer a theoretical guide for research into the distribution patterns of unconventional hydrocarbon reservoirs.

Shale oil and gas hold considerable exploration potential as significant unconventional hydrocarbon resources. The fracability of shales plays a vital role in the exploration and exploitation of shale oil and gas reservoirs and is typically measured using elastic parameters. In this study, we comprehensively investigate domestic and international advances in research on the elastic parameters of shales, along with associated issues and challenges. The results indicate numerous measurement methods for the elastic parameters of shales, including experimental methods (e.g., compression, ultrasonic measurement, nanoindentation, and acoustic logging) and theoretical calculation methods (e.g., digital core calculation, equivalent medium theory, and molecular dynamics simulation). Given the advantages, limitations, and application conditions of these methods, it is necessary to select scientific, accurate ones based on specific situations. Despite their relatively high accuracy, laboratory experimental methods are affected by sampling rates and experimental conditions. For instance, acoustic logging provides continuous, dynamic elastic parameters, capable of reflecting the mechanical properties of shales under instantaneous loading. However, these properties somewhat differ from those under long-term static loading in actual strata. Regarding theoretical calculation methods based on physical models, albeit with well-defined physical implications, these models require many input parameters and complex equations, which lead to reduced practicality. Additionally, these models typically neglect or make assumptions on non-primary factors excessively. For example, molecular dynamics simulation can simulate the elastic parameters of composite materials composed of multiple minerals while remaining simple and convenient to use. However, it still differs from actual geological models with complex and highly variable subsurface conditions, leading to discrepancies between simulation results and actual values. The elastic parameters of shales are primarily affected by factors including mineral composition, natural fractures, confining pressure, pore structure, diagenesis, and temperature. Additionally, they are influenced by organic matter characteristics, the properties and temperature of fluids within shales, sample size, bedding, and in-situ stress difference. Future studies should focus on the R&D of advanced technologies in terms of the quantitative relationships, multi-scale characteristics, and complex geologic environments of shales.

Exploring the structure and hydrocarbon generation characteristics of kerogen at a molecular scale and revealing its reaction pathway for hydrocarbon generation and generation model holds great significance for the study on the hydrocarbon generation of kerogen in low-maturity shales and shale oil exploration. A combination of analytical techniques including ultimate analysis, solid-state ¹³C nuclear magnetic resonance (¹³C NMR) spectroscopy, X-ray photoelectron spectroscopy (XPS), and Fourier transform infrared spectroscopy (FTIR), is applied to investigate the heteroatom morphology, carbon skeleton structure, and aliphatic and aromatic functional groups of kerogen in low-maturity shales from the 4th member of the Paleocene Shahejie Formation in the Shuguang area, Western Sag, Liaohe Depression. Accordingly, a two-dimensional average molecular structure model of kerogen is established with C₁₈₈H₃₁₀O₁₄N₄S, which boasts a high proportion (73.40 %) of aliphatics, a low proportion of aromatics, and long aliphatic chains (methylene chain carbon number: 5.04). The results of the reactive force field molecular dynamics (ReaxFF MD) simulation reveal that the mass fractions of gaseous hydrocarbons (C₁—C₄), light oil components (C₅—C₁₃), and heavy oil components (C₁₄—C₃₉) reach up to 41.32 % at 3500 K, 20.75 % at 3300 K, and 30.22 % at 2800 K, respectively, with a conversion rate of kerogen pyrolysis up to 61.67 %. The hydrocarbon generation process of kerogen in the shales progresses through multiple stages, including structural transformation, weak bond breaking, strong bond breaking, secondary cracking, and polycondensation reaction sequentially. During these stages, kerogen molecules undergo the bond breaking of heteroatoms and carbon-hydrogen atoms in both aliphatics and aromatics, as well as dehydrogenation-induced polycondensation reactions of aromatic rings.

Shale gas serves as a significant strategic successor resource for future oil and gas reserves and production in China. Thus, a profound understanding of the adsorption mechanism of shale gas in shale reservoirs is crucial to accurately predict and evaluate shale gas reserves. In this study, we utilized two simulation methods, molecular dynamics simulation and Giant Canonical Monte Carlo simulation to examine the adsorption characteristics of kerogen under varying temperature and pressure conditions. We compared the results under identical temperature and pressure conditions for different mineral–kerogen composite models. Moreover, we examined the effects of temperature, pressure, and mineral species on the kerogen adsorption mechanism. The results indicate that shale formations with high organic matter content and a substantial proportion of non-clay inorganic minerals, as well as those subjected to higher temperature and pressure conditions than the shallow layer, possess a greater capacity to accommodate shale gas. This study examined the adsorption mechanism of methane in shale gas using different mineral–kerogen composite models. The findings of this study provide more accurate guidance and support for efficient development of shale gas.

The Early Cambrian Yuertusi Formation (Є₁y) in the Tarim Basin of China deposits a continuously developed suite of organic-rich black mudstones, which constitute an important source of oil and gas reservoirs in the Paleozoic. However, its hydrocarbon generation and evolution characteristics and resource potential have long been constrained by deeply buried strata and previous research. In this paper, based on the newly obtained ultra-deep well drilling data, the hydrocarbon generation and expulsion model of Є₁y shale was established by using data-driven Monte Carlo simulation, upon which the hydrocarbon generation, expulsion, and retention amounts were calculated by using the diagenetic method. The research indicates that the Є₁y shale reaches the hydrocarbon generation and expulsion threshold at equivalent vitrinite reflectances of 0.46% and 0.72%, respectively. The cumulative hydrocarbon generation is 68.88 × 10¹⁰ t, the cumulative hydrocarbon expulsion is 35.59 × 10¹⁰ t, and the cumulative residual hydrocarbon is 33.29 × 10¹⁰ t. This paper systematically and quantitatively calculates the hydrocarbon expulsion at various key geological periods for the Є₁y source rocks in the study area for the first time, more precisely confirming that the black shale of the Є₁y is the most significant source rock contributing to the marine oil and gas resources in the Tarim Basin, filling the gap in hydrocarbon expulsion calculation in the study area, and providing an important basis for the formation and distribution of Paleozoic hydrocarbon reservoirs. The prospect of deep ultra-deep oil and gas exploration in the Tarim Basin is promising. Especially, the large area of dolomite reservoirs under the Cambrian salt and source rock interiors are the key breakthrough targets for the next exploration in the Tarim Basin.

Significant breakthroughs have been achieved in the exploration of Paleogene reservoirs in the Lufeng Depression. However, as drilling depth is becoming greater, the discovered oil and gas reservoirs show signs of transition from conventional to unconventional accumulations, and the identification of conventional and unconventional reservoir boundaries is of particular significance. Herein, the hydrocarbon dynamic field boundaries in the Lufeng Depression are comprehensively identified by the geological drilling result method, the sandstone pore throat radius critical value discrimination method and the dry layer drilling rate variation method; then, the hydrocarbon dynamic field is divided and the characteristics and differences of hydrocarbon accumulations in each hydrocarbon dynamic field are compared. The results show that the buoyancy-driven hydrocarbon accumulation depth in the Lufeng Depression is between 3,500-4,000 m, and the hydrocarbon accumulation depth limit is about 5,800 m. The focus of research on Paleogene oil and gas exploration in the Lufeng Depression should be placed on conventional oil and gas reservoirs in the free dynamic field and tight oil reservoirs in the reformed dynamic field. As for the Enping Formation and Upper Wenchang Formation, efforts should concentrate on conventional oil and gas reservoir exploration, and the tight reservoir of Lower Wenchang Formation should be explored in the high fracture density area in C-4 and C-8 well blocks and the west of C-8 well block of the Lufeng 13 sag. The research results of this paper are of great value in further increasing oil and gas production and the explorarion of reservoirs in the Lufeng Depression.