This study focuses on the PS8 well in the Penglai Gas Field (Sichuan Basin), a newly identified key exploration area, where high-yield gas testing has been achieved from the Ediacaran Fourth Member of the Dengying Formation. Comprehensive analyses of drilling cores, cuttings, thin sections, analytical data, well logging, and production testing data were conducted to investigate the main characteristics of the gas reservoir and the factors controlling the formation model of the reservoir. The results reveal that the reservoir rocks in the Fourth Member of the Dengying Formation are primarily algal-clotted dolomite, algal-laminated dolomite, and arenaceous dolomite. The reservoir porosity is dominated by secondary pores, such as algal-bonded framework pores, intergranular dissolved pores, and intercrystalline dissolved pores, which contribute to the overall low porosity and extremely low permeability. The gas reservoir is classified as a unified structural–lithological reservoir, with the upper sub-member of the Fourth Member serving as a completely gas-bearing unit. This unit is characterized as an ultra-deep, dry gas reservoir with medium sulfur and medium CO₂ contents. The development of this gas reservoir follows a “laterally generated and laterally stored, upper generation and lower storage” reservoir formation model. Regional unconformities and fracture systems developed during the Tongwan II Episode tectonic movement provide efficient pathways for hydrocarbon migration and accumulation. The high-quality source rocks in the lower Cambrian Qiongzhusi Formation serve as both the direct cap rock and lateral seal of the gas reservoir, creating an optimal source–reservoir spatial configuration. This study provides valuable insights into the giant gas reservoir of the Dengying Formation, which can aid in optimizing exploration activities in the Sichuan Basin.

The pore-throat structure of low- to ultralow-permeability reservoirs is complex, causing the permeability to vary greatly under similar porosity conditions. Moreover, the pore-throat structures are the key factors that controled the physical properties of such kind of reservoirs. Therefore, conventional reservoir evaluation methods can hardly meet the research needs of low- to ultralow-permeability reservoir exploration and development. We have conducted our research on Paleogene Shahejie and Neogene Dongying low- to ultralow-permeability reservoirs in the eastern Nanpu Sag of the Bohai Bay Basin to address this issue. Cores, thin sections, and scanning electron microscopy were used to analyze the pore-throat structures to determine the characteristics of low- to ultralow-permeability reservoirs, and a new parameter for evaluating low- to ultralow-permeability reservoirs is developed. The results of this research show that primary pores, secondary pores, and microfractures are developed in the study area and that the pore-throat shape is mainly flaky or curved flaky. The microscopic pore-throat structure controlled the reservoir physical properties and fluid mobility of these reservoirs, the permeabilities of these reservoirs are dependent on the pore throats, and the correlation between connected pores and permeability is strong. Based on the analysis of the pore-throat structure, as well as the maximum mercury saturation (S_max) and the residual mercury saturation (S_r) at the maximum pressure and the minimum pressure obtained by the mercury injection test, an evaluation of the reservoir by using the mobility parameter of fluid (Δfm = S_max-S_r) is proposed, and the pore-throat radius R₁₅ obtained by the mercury intrusion experiment has the best correlation with the fluid mobility parameters. The mobility parameters of fluid can effectively improve the accuracy of logging interpretation of low- to ultralow-permeability reservoirs and provide a scientific basis for the scale stimulation and effective development of low- to ultralow-permeability reservoirs.

The Upper Permian Changxing Formation reef-shoal carbonates in the Huanglongchang Structure, eastern Sichuan Basin, are important gas reservoirs, yet their characteristics and controlling mechanisms remain poorly understood. We integrated 481 core samples and 126 cast thin sections from 8 wells with logging, petrophysical, and structural data to characterize reservoir properties and controls. The results show that: (1) Reservoirs are dominated by oolitic, reef breccia, and rudstone dolomites, with secondary dissolution pores as the main storage space. They exhibit low porosity, low permeability, and strong heterogeneity, with porosity of 4%-12% and permeability of 0.1-10 mD. (2) The thermogenic dry gas contains 92.86%-97.41% methane. CaCl$_2$-type formation water has an average TDS of 110.15 g/L, indicating a strongly confined accumulation environment. (3) Platform-margin reef-shoal facies are most favorable for reservoir development, particularly back-reef shoals, with an average effective porosity of 8.75%. (4) Multi-stage dolomitization and dissolution are the principal constructive diagenetic processes. Burial dolomitization creates a compaction-resistant intercrystalline pore framework, while karstification and burial dissolution enlarge storage space. Yanshanian and Himalayan fractures further enhance permeability, with fracture intensity increasing toward structural highs and greater fold curvature. Therefore, overlap zones of platform-margin reef-shoal bodies and structural highs are most favorable for high-quality reservoirs. These results establish a coupled model of ``sedimentary facies constraint-diagenetic modification-tectonic fracture enhancement'' and provide guidance for reef gas exploration around the Kaijiang-Liangping Trough.

With the advancement of the Tingzikou Irrigation Area Water Diversion Project, the issue of harmful shallow underground gases in the tunnel has become increasingly prominent. Identifying the causes, sources, and migration processes of these harmful gases is crucial to prevent possible catastrophic impacts and mitigation during tunnel construction. Here, we apply an integrated approach of carbon isotope composition to analyze the geochemical characteristics of shallow natural gas components from a high-gas water diversion tunnel in the Tingzikou Irrigati Area. Results are integrated and compared with data from the Sichuan Basin fault system and isotopic values from different strata to provide further evidence of the source of shallow natural gas in the area. The geochemical characteristics of the gas samples reveal that the methane content is the most abundant, and constitutes as high as 45.16%, while carbon oxides are in the range of 0.02%–0.1%. Heavier hydrocarbons (C2+) account for 2.27%, and the dryness coefficient is 0.96. These major components indicate the presence of wet gas with relatively low thermal maturity. The alkane gases exhibit a normal carbon sequence, with δ¹³C₁ values less than −25‰, indicating that the gas originates from oil-type organic. The carbon dioxide is classified as Type II inorganic gas, and the hydrogen sulfide is attributed to thermochemical sulfate reduction origin. In the tunnel area, δ¹³C₂ ranges from −29.53‰ to −28.11‰, with an average of −28.80‰, which are similar to the ethane isotope values of the J₁l and J1m strata in the central Sichuan Basin, but heavier than those of the J1dn, J₁d, and T₂l strata, and significantly different from T₃x. This reveals that the shallow natural gas originates from the shallow oil and gas source rock layers of the Ziliujing Formation at the Ziliujing anticline, making it a “self-generated and self-stored” gas.

The eastern part of the Shichang Sub-sag in the Nanpu Sag is influenced by multiple provenance systems. However, there are divergent opinions regarding the directions of sediment supply and the relative contributions of different provenances to this area, which have led to controversies over the types of slope-breaks, the depositional models, and the sand-body distribution under different provenance regimes. These uncertainties have severely constrained the exploration of lithologic hydrocarbon reservoirs in the western slope area of the sub-sag. The provenance systems and the distribution range of sand bodies were clarified through Dickinson ternary diagrams, seismic reflection characteristics, as well as analyzing rock clastic grain components, heavy mineral assemblages, and sandbody distribution patterns. Research revealed that there are two main provenance areas supplying the Es3$^3$ submember in the eastern Shichang Subsag: one originating from the northeast and the other from the east. The ZTR index and sandbody distribution patterns indicate that the northeastern provenance exerts a widespread influence over the eastern Shichang Sub-sag and serves as the dominant sediment-supply area, whereas the eastern provenance has a comparatively limited impact. The northeastern provenance in the eastern part of the Shichang Sub-sag controls the fan-delta sand bodies on the western slope, which are favorable zones for lithologic reservoir development, whereas the eastern provenance controls the fan‑delta front sand bodies in the eastern sector, which are favorable zones for structural reservoir development. Provenance system determination in the eastern Shichang Subsag provides a reference for studying sedimentary systems and sandbody distribution under varying slope-break types and provenance controls, and additionally provides guidance for reserve growth and production enhancement efforts in the eastern Shichang Sub-sag.