Adsorption of hydrocarbons may significantly affect hydrocarbon migration in unconventional reservoirs. Clay minerals form the primary adsorbent surfaces for hydrocarbons adsorbed in mudstone/shale. To study the adsorption properties of hydrocarbons (n-decane (C₁₀H₂₂), methyl cyclohexane (C₇H₁₄) and toluene (C₇H₈)) on clay minerals (i.e., cookeite, ripidolite, kaolinite, illite, illite/smectite mixed-layer, Na-montmorillonite and Ca-montmorillonite), hydrocarbon vapor adsorption (HVA) tests were conducted at 298.15 K. The results showed that (i) the adsorption amounts of C₁₀H₂₂, C₇H₁₄ and C₇H₈ ranged from 0.45–1.03 mg/m², 0.28–0.90 mg/m² and 0.16–0.53 mg/m², respectively; (ii) for cookeite, ripidolite and kaolinite, the adsorption capacity of C₁₀H₂₂ was less than C₇H₁₄, which was less than C₇H₈; (iii) for illite, Na-montmorillonite and Ca-montmorillonite, the adsorption capacity of C₁₀H₂₂ was greater than that of C₇H₈, and the adsorption capacity of C₇H₁₄ was the lowest; (iv) for an illite/smectite mixed-layer, C₇H₁₄ had the highest adsorption capacity, followed by C₁₀H₂₂, and C₇H₈ had the lowest capacity. Adsorption properties were correlated with the microscopic parameters of pores in clay minerals and with experimental pressure. Finally, the weighted average method was applied to evaluate the adsorption properties of C₁₀H₂₂, C₇H₁₄ and C₇H₈ on clay minerals in oil-bearing shale from the Shahejie Formation of Dongying Sag in the Bohai Bay Basin, China. For these samples, the adsorbed amounts of C₇H₁₄ ranged from 18.03–28.02 mg/g (mean 23.33 mg/g), which is larger than that of C₁₀H₂₂, which ranges from 15.40–21.72 mg/g (mean 18.82 mg/g). The adsorption capacity of C₇H₈ was slightly low, ranging from 10.51–14.60 mg/g (mean 12.78 mg/g).

Hydrocarbon vapor adsorption experiments (HVAs) are one of the most prevalent methods used to evaluate the proportion of adsorbed state oil, critical in understanding the recoverable resources of shale oil. HVAs have some limitations, which cannot be directly used to evaluate the proportion of adsorbed state oil. The proportion of adsorbed state oil from HVA is always smaller than that in shale oil reservoirs, which is caused by the difference in adsorption characteristics of liquid and gaseous hydrocarbons. The results of HVA need to be corrected. In this paper, HVA was conducted with kaolinite, an important component of shale. A new method is reported here to evaluate the proportion of adsorbed state oil. Molecular dynamics simulations (MDs) of gaseous/liquid hydrocarbons with the same temperature and pressure as the HVAs were used as a reference to reveal the errors in the HVAs evaluation from the molecular scale. We determine the amount of free state of hydrocarbons by HVAs, and then calculate the proportion of adsorbed state oil by the liquid hydrocarbon MD simulation under the same conditions. The results show that gaseous hydrocarbons adsorptions are monolayer at low relative pressures and bilayer at high relative pressures. The liquid hydrocarbons adsorption is multilayer adsorption. The adsorption capacity of liquid hydrocarbons is over 2.7 times higher than gaseous hydrocarbons. The new method will be more effective and accurate to evaluate the proportion of adsorbed state oil.

The Ri-Qing-Wei Basin is a newly discovered Late Mesozoic rift basin on the eastern Shandong coast in recent years. Thick, continuous deposited source rocks are found in the Lingshan Island scientific drilling project. Therefore, it is necessary to evaluate the distribution and hydrocarbon generation potential of source rocks in this area. Organic geochemical experiments were carried out on samples from the core of LK-1 and outcrops in the Lingshan Island, the Laoshan area, and the Jimo Zhougezhuang area to evaluate the maturity, abundance, and type of organic matter in source rocks. The results show that the cumulative thickness of the source rocks in the study area is more than 500 m, and the TOC content is generally greater than 1.0%. The organic matter type is good (mainly type II₁ and type II₂ kerogen) and the R_o value is more than 2.0. The thermal evolution degree of the organic matter is high with natural gas predominantly generated. We carried out Rock-Eval, PY-GC and gold tube experiments on low-maturity samples of Laikong 2 and established a chemical kinetic model to quantitatively evaluate the study area in combination with sedimentary burial history and thermal history data. The results show that the total resources of the five sags in the study area are about 476 billion cubic meters, and the average resource intensity is about 82.2 million cubic meters/km². Among them, the resource intensities of the Lingshan Island Sag and Laoshan Sag are 112.6 million cubic meters/km² and 98.8 million cubic meters/km², respectively. Studied sites are “small and fertile” and may be used as favorable exploration prospect areas.

Hybrid sedimentary rocks (HSR) represent a significantreservoirtype in fine-grained sediments. However, the classification and understandingof HSR reservoirs, including their storage mechanisms and identificationof optimal "sweet spots," have been limited due to thelack of clarity regarding the multiple sources of components and theirmixing processes. This study focuses on the Lucaogou formation ofJimusaer Sag and aims to highlight the reservoir classification principles,controlling factors, and evolutionary patterns associated with thecomponents of HSR, beginning with examining the microscopic pore structure.The analysis of the microscopic pore structure characteristics revealsthe presence of five distinct reservoir types within the HSR. Thequality of these reservoirs is governed by various factors, includingthe composition and support mode of particles, diagenesis, provenance,and sedimentary microfacies. In regions near a provenance with stronghydrodynamic conditions, the HSR predominantly exhibits type I andtype II reservoirs, characterized by numerous coarse-grained componentsand a granular-support mode. As the distance from the provenance increases,transitioning into medium hydrodynamic conditions, the HSR shiftsto an interbedded-support mode, primarily developing type III reservoirs.In areas far from the provenance with weak hydrodynamic conditions,HSR reservoir types primarily consist of type IV and type V. Additionally,diagenetic effects such as compaction and calcite cementation furtherdeteriorate intergranular and dissolution pores, consequently diminishingreservoir quality. Notably, during the mixing deposition processesof sand and dolomite, the developmental mode of HSR shifts from typeI to type II and type III. Likewise, in the mixing deposition of mudand sand, the HSR transitions from type II to type III and type IV.Similarly, the mixing deposition of dolomite and mud leads to a changein the developmental mode of HSR from type III to type IV and typeV. Moreover, this study effectively predicts the occurrence of "sweetspots" using reservoir classification, which reveals theircontinuous distribution. These findings provide a geological foundationfor evaluating "sweet spots" and testing the oil productionin HSR reservoirs.

The Yinggehai Basin is situated in the Yinggehai Sea, between Vietnam and the southwest of Hainan Island in China. This location is home to two significant shallow-gas field clusters, known as the Dongfang and Ledong Areas, where the actual controlled gas reserves have surpassed the anticipated resource amounts based on current knowledge of gas origins. It was traditionally thought that the gas reserves in the Dongfang Area were primarily derived from the Meishan Formation source rocks, whereas those in the Ledong Area came from source rocks in both the Meishan and Sanya Formations. Given that the carbon isotopes of kerogens in the Meishan Formation are heavier than those in the Sanya Formation, it was expected that natural gas in the Dongfang Area would exhibit heavier carbon isotopes compared with the Ledong Area. Nevertheless, this expectation was challenged by the measured carbon isotope values of natural gas in these areas. Thus, accurately determining the contributions of gas sources has emerged as a crucial aspect in the comprehensive investigation of natural gas accumulation and distribution patterns within these regions. This study performed thermal simulation experiments on mudstone samples from the Meishan and Sanya Formations to establish models for hydrocarbon generation dynamics and methane carbon isotope fractionation and to reconstruct the history of hydrocarbon generation and the evolution of methane carbon isotopes. The contributions of gas sources for the Dongfang and Ledong Areas were examined through the integration of data concerning the basin’s fault system and the history of pressure evolution. The findings indicated that besides the diapir in both areas, a superimposition zone of faults from the Meishan and Sanya Formations in the Dongfang Area could act as a conduit for source reservoirs. Early natural gas from the Sanya Formation, prior to 5.5 Ma in the Dongfang Area, might first fill the Meishan reservoir before contributing to the formation of shallow-gas reservoirs, thus facilitating a “relay accumulation” process. This resulted in the presence of lighter carbon isotopes in hydrocarbon gases within the Dongfang Area. By evaluation of the principal hydrocarbon generation period of the source rocks, the effective period for source–reservoir channels, and the reservoir formation period, the optimum gas supply times from the source rocks were identified. Consequently, a map illustrating the gas source contribution patterns for the gas reservoirs in the Dongfang and Ledong Areas was created. Furthermore, the gas source contribution ratios for the Dongfang and Ledong gas fields were determined to be 65%:35% and 50%:50%, respectively, from the Meishan and Sanya source rocks, according to the methane carbon isotope fractionation model.