By investigating the evolution of shale gas generation, storage, adjustment and accumulation under different structural settings in superimposed basins, this study elucidates the differential accumulation mechanisms of shale gas. An improved evaluation method of shale gas content evolution in superimposed basins is proposed. This method incorporates the coupling effect of key geological factors such as temperature, pressure, organic matter abundance, maturity, and pore characteristics on the content and occurrence state of shale gas, as well as the configuration relationship between shale gas generation and storage throughout geological history. Using this approach, the gas evolution histories of the Longmaxi Formation shales in wells N201 and PY1 are reconstructed under varying geological conditions. The Longmaxi Formation shales in these wells are dominated by type Ⅰ kerogen, with original total organic carbon (TOC_o) contents of 6.20 wt% and 4.92 wt%, respectively, indicating differences in the initial material basis for gas generation. At the maximum burial depth of approximately 5000 m, the Longmaxi Formation shale in well N201 exhibits a formation pressure coefficient of 2.05, an organic matter maturity of 2.2%, and organic pores accounting for 68% of the total porosity. The gas generation quantity (Q_g) reaches 19.24 m³/t, while the gas storage capacity (Q_s) is 4.30 m³/t. The actual total gas content (Q_a), constrained by Q_s, is 4.30 m³/t, with free gas comprising 94%. Following relatively moderate tectonic uplift, the Q_a in well N201 decreases to 4.03 m³/t, with free gas accounting for 63%. In contrast, the Longmaxi Formation shale in well PY1 reached a maximum burial depth of 6300 m, associated with a formation pressure coefficient of 1.62, organic matter maturity of 2.5%, and organic pore proportion of 67%. Here, Q_g is 16.87 m³/t, and both Q_s and Q_a are 3.65 m³/t, with free gas accounting for 98%. After intense tectonic uplift, Q_a declines to 2.72 m³/t, and the proportion of free gas drops to 51%. Finally, a four-stage differential accumulation model of shale gas is established: Slow gas generation and only adsorbed gas occur in stage Ⅰ, which is primarily controlled by TOC content; both adsorbed gas and free gas present in stage Ⅱ, with free gas becoming dominant; rapid gas generation and free gas predominance are controlled by temperature and porosity in stage Ⅲ; and gas adjustment and accumulation are primarily controlled by temperature and pressure in stage Ⅳ.

The global investigation of natural gas hyate (NGH) has made rapid progress, and at least 30 groups of scientists have carried out quantitative evaluation of NGH resource potential since 1973. Based on the academic thought of Whole Petroleum System, Professor Pang Xiongqi and others combined the formation and distribution of natural gas hydrate with conventional oil and gas and unconventional oil and gas, and established a quantitative relationship model between them based on the idea of mass balance. Under the constraints of the main control factors and the actual test data, the global natural gas hydrate recoverable resources quantity is calculated as 41.46×10¹² m³. Based on the principle of mass balance, there are seven main controlling factors to calculate the recoverable resources of global natural gas hydrate. It includes the area of the free hydrocarbon dynamic field (A_F-HDF), the thickness of the free hydrocarbon dynamic field (H_F-HDF), the area of the hydrate stability zone (A_GHSZ), the thickness of the hydrate stability zone (H_GHSZ), the amount of conventional oil and gas resources (Q_c1), the amount of heavy oil asphalt resources (Q_c2) and the recovery coefficient (R_GH). Taking into account both the biological degradation and thermal degradation mechanisms of hydrates, the source rock gas supply ratio (g) is introduced considering the difference in volume coefficients between hydrates and conventional oil and gas, their respective volume coefficients B_ghand B_g are introduced. In the case that the principle of the method is completely correct, the sensitivity and reliability of the numerical simulation results need to be analyzed considering that there are many influencing factors and their respective variation ranges are large. In this paper, the sensitivity of the mass balance method to obtain the assessment results of global NGH recoverable resources are studied. The results showed that the recoverable coefficient exhibits the highest sensitivity (31.13%), followed by Q_c1, Q_c2, A_F-HDF, A_GHSZ, H_GHSZ and H_F-HDF, with values of 22.70%, 13.38%, 12.44%, 8.89%, 6.12% and 5.34%, respectively.Then under the joint control of all factors, applying Monte Carlo simulation to assess credibility.The global mode and mean values of recoverable hydrate resources are 78.09×10¹² m³ and 86.06×10¹² m³ respectively, and the confidence of ±50% before and after the key value is 88.95%, indicating a high reliability. Simultaneously, validation was conducted based on the assessment results of previous researchers.The effective method to further improve the accuracy of global hydrate recoverable resources evaluation is to obtain more actual test production data and reduce the uncertainty between them.

The whole petroleum system (WPS) theory serves to introduce a new perspective for hydrocarbon exploration, contributing to significant achievements in exploration practices across multiple basins. Under actual geological conditions, hydrocarbon reservoirs tend to exhibit complex formation processes due to the interplay of multiple dynamic forces. Identifying the dynamic types that drive the formation of complex hydrocarbon reservoirs within a WPS and quantifying their respective contributions have become a key challenge in current research on hydrocarbon accumulation. As a distinct category of distal tight hydrocarbon reservoirs in the WPS, the tight sandy conglomerate reservoirs of the Triassic Baikouquan Formation in the Mahu Sag, Junggar Basin represent a globally rare sandy conglomerate oil play with abundant reserves. A new technique for identifying the buoyancy-driven hydrocarbon accumulation depth (BHAD) in a WPS reveals that the BHAD of the Baikouquan Formation corresponds to a critical porosity of 12% and a critical permeability of 1 × 10^-3 μm². Accordingly, four driving forces of hydrocarbon migration and accumulation in the formation's sandy conglomerate oil reservoirs are identified, namely, the buoyancy (Ⅰ) and non-buoyancy forces (Ⅱ), tectonic stress (Ⅲ₁), and the geofluid activity (Ⅲ₂), which contribute 13.10%, 45.32%, 37.44%, and 4.14%, respectively to the proven reserves of these reservoirs. The contributions of major driving forces indicate that the sandy conglomerate oil reservoirs represent a joint-dynamic accumulation type dominated by non-buoyancy and tectonic stress reformation. Petrographic and fluid inclusion analyses reveal that oil reservoirs in the Baikouquan Formation underwent two key hydrocarbon charging events during the Early Jurassic and Early Cretaceous. During the first accumulation stage, tight and conventional oil reservoirs are formed under the action of capillary pressure and buoyancy, respectively. In contrast, during the second accumulation stage, tight oil reservoirs are primarily formed through capillary pressure. Currently, these oil reservoirs have evolved into two distinct types: low-porosity, low-permeability tight reservoirs formed by capillary pressure and tectonic stress-reformed low-porosity, high-permeability fractured oil reservoirs. Analysis of the coupling relationships between geological factors during key accumulation stages reveals that the sandy conglomerate oil reservoirs in the Baikouquan Formation exhibit a composite accumulation model characterized by multiple driving forces, multiple stages, and multi-lithofacies. Determining the dynamic mechanisms behind hydrocarbon accumulation in distal tight hydrocarbon reservoirs will provide a new philosophy for the efficient exploration and exploitation of these reservoirs while also offering an important practical basis for improving the WPS theory.

Deep carbonate hydrocarbon reservoirs in the platform-basin area of the Tarim Basin represent a significant hydrocarbon pay interval in China, holding considerable resource potential. However, their transformation characteristics, genetic models, and distribution patterns remain poorly understood due to the influence of multi-phase tectonic activities, multi-stage hydrocarbon charging, and late-stage adjustments and modifications. These hinder the progress of effective deep and ultra-deep hydrocarbon exploration therein. Based on the theory of the whole petroleum system, we systematically investigate the transformation processes and genetic models of the Lower Paleozoic carbonate hydrocarbon reservoirs in the platform-basin area of the Tarim Basin. The results indicate that the reformed carbonate hydrocarbon reservoirs in the platform-basin area exhibit several distinct characteristics: (1) tectonization-induced failure of the dynamic boundaries for hydrocarbon accumulation; (2) tectonic movement-induced failure of the dynamic fields for hydrocarbon accumulation and migration; (3) the transformation of early-stage continuous, tight reservoirs into conventional fractured, fractured-vuggy, or pore-cavity reservoirs; (4) the formation of superimposed, consistently distributed hydrocarbon reservoirs, and (5) the emergence of novel fault-karst hydrocarbon reservoirs. These reservoirs are governed by the dynamic coupling of multiple factors, including sedimentary evolution, tectonic movements, hydrocarbon accumulation and migration stages, and preservation conditions. The failure of the dynamic boundaries for hydrocarbon accumulation occurred after three evolutionary stages of physicochemical effects. The reformed hydrocarbon reservoirs display an orderly distribution pattern characterized by vertical layering and lateral zoning. The vertical layering is primarily determined by the differences in lithologic assemblages and depositional environments, while the lateral zoning is controlled by the developmental degrees of faults and unconformities. In the platform-basin area, reef-shoal and unconformity-controlled pore-cavity reservoirs are predominantly distributed within free hydrodynamic fields. In contrast, fault-controlled fractured reservoirs are typically found in constrained hydrodynamic fields between the buoyancy-driven hydrocarbon accumulation depth (BHAD) and the baseline of hydrocarbon accumulation.

The whole petroleum system in the Permian Fengcheng Formation of the Mahu Sag within the Junggar Basin comprises conventional, tight, and shale hydrocarbon reservoirs, whose formation and distribution are governed by the coupling effects of multiple dynamic fields. Using statistical and geological analyses, we systematically investigate the dynamic boundaries among the three reservoir types and the differences in the contributions of migration dynamics to these reservoirs. Based on data from physical property tests of 1024 conventional and unconventional reservoir samples, 1235 high-pressure mercury injection (MICP) experiments, and pyrolysis of 1630 samples, we define the quantitative relationships of porosity, permeability, and maximum pore-throat radius with burial depth. Accordingly, the critical parameters are determined for the buoyancy-driven hydrocarbon accumulation depth (BHAD), hydrocarbon accumulation depth limit (HADL), and active source-rock depth limit (ASDL). The results indicate that the BHAD corresponds to a burial depth of 4290.86 m (porosity: 8%, permeability: 1 × 10^-3 μm², pore-throat radius: 0.800 μm). The HADL is approximately 8000.00 m (porosity: 2%, pore-throat radius: 0.025 μm), while the ASDL corresponds to a critical burial depth of approximately 10000.00 m. Using the quadripartite method, we quantitatively assess the contributions of buoyancy, capillary pressure difference, tectonic stress, and fluid dissolution. The results reveal that the conventional hydrocarbon reservoirs (above the BHAD) are dominated by buoyancy-driven migration, primarily found in the deltaic plain facies along the margin of the Mahu Sag. In contrast, the hydrocarbon migration of unconventional reservoirs (below the BHAD) is controlled by capillary pressure difference, as well as hydrocarbon generation and expulsion dynamics. These reservoirs are principally distributed in the slope transition zone and the sag center, characterized by delta front and shallow to semi-deep lacustrine subfacies. By determining the quantitative relationships of porosity, permeability, and maximum pore-throat radius with burial depth and by assessing the dynamic contributions using the quadripartite method, this study serves to advance the theoretical framework of the hydrocarbon accumulation dynamics in the whole petroleum system, providing scientific support for the collaborative exploration and efficient exploitation of conventional and unconventional hydrocarbon resources in the Junggar Basin and comparable geological settings.

Accurately measuring the wetting angles, interfacial tension, and pore-throat radii of reservoir rocks under high temperature and pressure conditions or in ultra-tight reservoir environments remains challenging due to laboratory limitations and instrument constraints. These challenges complicate the determination of capillary pressure during hydrocarbon migration and accumulation. Given this, we calculate the wetting angles of the calcite, montmorillonite, quartz, and feldspar surfaces, as well as oil-water and gas-water interfacial tension, under relatively low temperature and pressure conditions using molecular dynamics simulation. After validating the high consistency between the simulation results and experimental data, we expand this method to high temperature and pressure conditions to simulate the corresponding variations in the above parameters. Furthermore, we calculate the pore-throat radii of reservoirs using the multiple linear regression method. Through systematic simulations based on the regional settings of the Junggar, Ordos, and Songliao basins, we obtain data on burial depth-varying wetting angles, interfacial tension, and pore-throat radii of sandstone, volcanic, and carbonate reservoirs under high-, medium-, and low-temperature geothermal fields in China. Accordingly, the quantitative relationships are established between these parameters and the temperature-pressure conditions of petroliferous basins. The simulation results indicate that the water wetting angles of calcite, montmorillonite, quartz, and feldspar decrease gradually with increasing temperature, suggesting enhanced hydrophilicity. In contrast, the water wetting angles of these minerals increase with pressure, leading to reduced hydrophilicity. Generally, in oil reservoirs, calcite tends to exhibit oil-wet behavior, montmorillonite shows neutrality to water-wet characteristics, while quartz and feldspar primarily display water-wet properties. The oil-water interfacial tension decreases gradually with rising temperature but increases progressively with pressure. In contrast, the gas-water interfacial tension decreases with rising temperature and declines further with increasing pressure. The pore throat radii of rocks show certain correlations with porosity and permeability, suggesting that reservoir physical properties play a significant role in fluid migration. The minerals exhibit significantly different wettability, interfacial tension, and pore-throat structures across varying geothermal fields. Their wetting angles trend downward with increasing geothermal gradient. Meanwhile, their interfacial tension also decreases gradually with increasing geothermal gradient, which reduces molecular interactions at oil-water or gas-water interfaces, thereby enhancing fluid mobility.

The theory of the whole petroleum system (WPS) defines the orderly distribution of conventional, tight, and shale reservoirs, providing an important theoretical basis for the combined evaluation, exploration, and exploitation of conventional and unconventional hydrocarbon reservoirs. However, during the evolution of the WPS, complex hydrocarbon reservoirs are formed by the superimposed, composite hydrocarbon accumulation processes characterized by multiple driving forces, multiple stages, and diverse elements. It’s hard to identify and explain these complex reservoirs using the orderly distribution pattern of various hydrocarbon reservoirs. Based on dynamic hydrocarbon accumulation processes, we categorize and analyze typical hydrocarbon reservoirs across six major basins of China. Furthermore, we explore the mechanisms controlling the conversion between conventional and unconventional hydrocarbon reservoirs during the evolution of the WPS. The results indicate that all types of hydrocarbon reservoirs exhibit genetic correlations according to the basic principle of the WPS. As hydrocarbon dynamic fields evolve, the formation and development of deep media (especially carbonate reservoirs) are governed by compaction and diagenesis, while intensively reformed by geofluid activities and tectonic stress, among others. A distinctive distribution pattern of hydrocarbon reservoirs occurs as a result. Systematic analysis reveals four conversion models between conventional and unconventional hydrocarbon reservoirs, namely, compaction-induced tightness, stress reformation, geofluid reformation, and special medium reformation. The combined effects of multiple geological processes lead to more complex hydrocarbon accumulation characteristics and reservoir distribution patterns. This study holds great significance for deepening the understanding of the dynamic evolution process and mechanisms of the WPS, providing a theoretical basis for determining the formation and distribution patterns of hydrocarbon reservoirs in the WPS under complex geological conditions.

The concept of the whole petroleum system (WPS)proposed and the ordered distribution pattern of conventional and unconventional hydrocarbon reservoirs established serve to unify petroleum geology theories, providing an entirely new theory and methods for guiding hydrocarbon exploration and exploitation. However, when applied to complex geological conditions such as those of superimposed basins in China, the WPS theory, originally formulated under general geological conditions, encounters several challenges. First, due to the lack of objective indices for quantitative characterization and the disruptions caused by late-stage tectonic activities, the idenfitication or prediction of buoyancy-driven hydrocarbon accumulation depth (BHAD) is hard in practice. Second, the formation and distribution of hydrocarbon reservoirs are governed by the combined effects of multiple driving forces, multiple stages, and diverse elements, complicating the identification of the hydrocarbon accumulation dynamics and reservoir types. Third, reservoirs such as those of the carbonate and clastic types exhibit varying wettability and interfacial tension properties, which lead to difficulties in predicting the maximum burial depth of hydrocarbon reservoirs and favorable hydrocarbon enrichment areas under actual geological conditions. Last, during the evolution of the WPS, hydrocarbon migration and accumulation are controlled by multiple factors including dynamic force types, capillary pressure differences between source rocks and reservoirs, hydrocarbon fluid properties, and tectonic activities. Consequently, establishing the hydrocarbon enrichment model of the WPS remains a challenge. To address these challenges, we explore various methods and technologies based on data from globally discovered hydrocarbon reservoirs, including their physical properties, productivity variations, and wettability. Accordingly, we develop new methods for identifying the BHAD, assessing hydrocarbon accumulation dynamics, and predicting the maximum burial depth of oil and gas resources. Furthermore, we determine the hydrocarbon enrichment model of the WPS. The results of this study offer new approaches to improve, develop, and apply the WPS theory under complex geological conditions.

Volcanic rocks in the Permian Jiamuhe Formation of the Jinlong oilfield in the Junggar Basin exhibit unclear lithofacies types and dominant reservoir distribution, which hinder the exploitation of the oil and gas resources therein. To address these challenges, we systematically analyze the volcanic facies types, reservoir physical properties, and storage space characteristics in the study area using data from core observations, log analysis, and laboratory tests. Accordingly, we establish lithofacies assemblage models, while clarifying their controlling effects on productivity. The results indicate that the volcanic rocks in the Jinlong oilfield in the Junggar Basin can be categorized into three facies:explosive, overflow, and volcanic sedimentary facies. The explosive facies, among others, consists primarily of welded volcaniclastic rocks and andesitic volcanic breccias, and exhibits an average porosity exceeding 10 %, forming dominant reservoirs. While the overflow facies is dominated by lavas, featuring an average porosity of below 6 %, and the volcanic sedimentary facies exhibits poor physical properties. In the volcanic reservoirs in the study area, vesicles, intraamygdale pores, and dissolution pores predominate, with a minor presence of primary intergranular pores. Additionally,dissolution vugs are most developed at the top of the explosive and overflow facies. Fractures in the volcanic reservoirs are dominated by structural and dissolution fractures, with developmental degrees closely related to their distance from faults. The intermediate-acidic overflow facies mainly exhibits oblique and reticulate fractures, while the mafic overflow facies is dominated by high-angle, straight-split fractures. The study area exhibits four lithofacies assemblages: interbedded intermediate-acidic pyroclastic flow subfacies and intermediate-acidic overflow subfacies, frequently interbedded mafic pyroclastic flow subfacies and mafic overflow subfacies, interbedded neutral air-fall subfacies and neutral overflow subfacies, and interbedded neutral air-fall subfacies and intermediate-acidic pyroclastic flow subfacies. The interbedded neutral air-fall subfacies and intermediate-acidic pyroclastic flow subfacies exhibits the highest productivity, followed by interbedded intermediate-acidic pyroclastic flow subfacies and intermediate-acidic overflow subfacies and interbedded neutral air-fall subfacies and neutral overflow subfacies, and with the frequently interbedded mafic pyroclastic flow subfacies and mafic overflow subfacies coming at last in daily production. The productivity of the volcanic reservoirs is governed most significantly by the effective reservoir thickness and oil saturation, followed by porosity and formation pressure.

As the main factor influencing the flow and preservation of underground fluids, wettability has a profound impact on CO₂ sequestration (CS). However, the influencing factors and internal interaction mechanisms of shale kerogen wettability remain unclear. In this study, we used molecular dynamics to simulate the influence of temperature, pressure, and salinity on wettability. Furthermore, the results were validated through various methods such as mean square displacement, interaction energy, electrostatic potential energy, hydrogen bonding, van der Waals forces, and electrostatic forces, thereby confirming the reliability of our findings. As temperature increases, water wettability on the surface of kerogen increases. At CO₂ pressures of 10 and 20 MPa, as the temperature increases, the kerogen wettability changes from CO₂ wetting to neutral wetting. As the CO₂ pressure increases, the water wettability on the surface of kerogen weakens. When the pressure is below 7.375 MPa and the temperature is 298 or 313 K, kerogen undergoes a wettability reversal from neutral wetting to CO₂ wetting. As salinity increases, water wettability weakens. Divalent cations (Mg²⁺ and Ca²⁺) have a greater impact on wettability than monovalent cations (Na⁺). Water preferentially adsorbs on N atom positions in kerogen. CO₂ is more likely to form hydrogen bonds and adsorb on the surface of kerogen than H₂O. As the temperature increases, the number of hydrogen bonds between H₂O and kerogen gradually increases, while the increase in pressure reduces the number of hydrogen bonds. Although high pressure helps to increase an amount of CS, it increases the permeability of a cap rock, which is not conducive to CS. Therefore, when determining CO₂ pressure, not only a storage amount but also the storage safety should be considered. This research method and results help optimize the design of CS technology, and have important significance for achieving sustainable development.