The vague understanding of the coupling relationship among natural gas charging, reservoir densification, and pressure evolution restricted the tight gas exploration in the Lower Shihezi Formation of the Hangjinqi area, north Ordos Basin. In this study, the quantitative porosity evolution model, the pressure evolution process, and the natural gas charging history of tight sandstone reservoirs were constructed by integrated investigation of the reservoir property, the thin section, SEM and cathode luminescence observations, the fluid inclusion analysis and the 1D basin modeling. The results show that the compaction and cementation reduced the primary porosity by 21.79% and 12.41%, respectively. The densification of the reservoir occurred at circa 230 Ma, which was before the natural gas charging time from 192 to 132 Ma. The paleo-overpressure within the tight reservoirs occurred since the Middle Jurassic with the pressure coefficients between 1.1 and 1.55. The continuous uplifting since the Late Cretaceous resulted in the under- and normal-pressure of the Lower Shihezi Formation with the pressure coefficients ranging from 0.67 to 1.05. The results indicate that the densification of the reservoirs was conducive to the formation of paleo-pressure produced by gas generating. The gas predominantly migrated vertically, driven by gas expansion force rather than buoyance and displaced the pore water in the reservoirs near source rocks.

To elucidate the reservoir characteristics of organic-rich siliceous shale of the Upper Permian Dalong Formation in western Hubei, this study focused on the drilling cores of Well ED-2. Various techniques, including a mineral composition analysis, an organic carbon content analysis, a vitrinite reflectance measurement, a total porosity determination, field emission scanning electron microscopy (FE-SEM), and low-pressure CO₂ and N₂ physical adsorption tests, were employed to analyze the mineralogy, organic geochemistry, total porosity, and pore structure characteristics. Additionally, the factors influencing the reservoir performance of the Dalong Formation shale were investigated. The results indicated that the Dalong Formation’s shale was characterized as an organic-rich siliceous shale. Organic matter was mainly of sapropelic type, with a relatively high thermal evolution degree and Ro ranging from 2.59% to 2.76%. The total porosity of the Dalong Formation’s siliceous shale was low, indicating poor reservoir properties. Organic matter pores were highly developed, mainly the ones formed after the hydrocarbon generation of solid asphalt. Micropores and mesopores were the dominant pore types in the shale, with macropores being significantly less abundant. The study further revealed that the pore volume and specific surface area exhibited a significantly positive correlation with total organic carbon (TOC) content and clay minerals, while demonstrating a weak negative correlation with quartz content. The comprehensive analysis revealed that there were two factors contributing to the poor physical properties of organic-rich siliceous shale in the Dalong Formation. Firstly, in siliceous shale with a high quartz content, the siliceous component was partly derived from the siliceous cementation of hydrothermal fluids. This process led to the formation of secondary quartz that filled intergranular pores, resulting in a decrease in macropore volume, total porosity, and a weak negative correlation with quartz content. Secondly, in siliceous shale with a relatively high clay mineral content, the organic matter was subjected to stronger compaction due to the relatively low content of brittle minerals. This compaction caused the destruction of most macropores, leaving behind primarily micropores and mesopores. Consequently, the average pore size decreased, leading to poor physical properties.

Organic matter (OM)-hosted pores play a crucial role in unconventional shale reservoirs, with their development influenced by OM type and thermal maturity across terrestrial, transitional, and marine deposits. In this study, a comparative analysis of porosity and pore structures is presented using organic petrographical, petrophysical, and mineralogical methods on organic-rich samples from diverse depositional environments. A pore evolution model for these sediments in different settings is proposed. Results show that kerogen particles in terrestrial shales at low and moderate thermal maturity (Dameigou Formation and Qingshankou Formation) are mostly nonporous. Transitional shales (Longtan Formation) contain vitrinite and inertinite, with only some inertinite exhibiting visible primary pores. In marine shales at higher maturity (late oil window; Dalong Formation), the interparticle pore space is occupied by solid bitumen, and secondary porosity is present at higher maturity, approaching the thermal gas generation stage. In over-mature marine shales (Wujiaping and Daye Formations), secondary pores are densely distributed within pyrobitumen. A negative correlation between organic carbon content and pore volume is observed in low-maturity lacustrine and transitional shales due to poorly developed kerogen-bound pores and interparticle pore occlusion by solid bitumen. However, over-mature marine shales exhibit a strong positive correlation due to extensive secondary porosity in pyrobitumen. Thus, pore evolution within OM is controlled by kerogen type and maturity. In oil-prone marine and lacustrine shales, secondary porosity in solid bitumen and pyrobitumen increases with thermal maturity. In contrast, terrestrial kerogen rarely forms solid bitumen and mainly develops micropores rather than mesopores at high maturity.

Exploration practice has proved that preservation conditions are one of the critical factors contributing to shale gas enrichment in the Middle Yangtze area. Well Yidi2 is the discovery well of Cambrian shale gas in this area. The paleo-fluid evolution and its implication for preservation conditions of shale gas remains unclear, posing challenges for shale gas exploration and development. In this study, through systematic analysis of fluid inclusions in fractrue-filling vein of the entire core section of this well, combined with carbon and oxygen isotope tests of veins and host rocks, a paleo-fluid profile was established to explore the formation environment of Cambrian paleo-fluids and their implications for the preservation conditions of the Shuijingtuo Formation (SJT Fm.) shale gas. The results suggest that fractures in the SJT Fm. shale at the base of Cambrian Series 2 mainly formed during the deep burial hydrocarbon generation stage, trapping a large number of liquid hydrocarbon inclusions. Subsequently, numerous high-density methane inclusions and a few of gas-liquid two-phase inclusions were trapped. The SO₄²⁻, Ca²⁺ and Mg²⁺ content of fluid inclusion groups in the veins decreased from the Qinjiamiao Formation (QJM Fm.) at the bottom of Cambrian Series 3 upward and downward respectively, and the rNa⁺/rCl⁻ ratio was the lowest in the SJT Fm. and increased overall upward. The δ¹³C values of calcite veins in Tianheban Formation (THB Fm.)-Shipai Formation (SP Fm.) of the middle Cambrian Series 2 and the Loushanguan Formation (LSG Fm.) of the Cambrian Series 3 were lighter compared to the host rocks. Results indicate the later tectonic activities in this area were relatively weak, and the shale interval remained in a state of high gas saturation for a long time. The QJM Fm. was the main source of high-salinity brine, and the SJT Fm. had strong self-sealing properties and was relatively less affected by external fluids. However, the pressure evolution of high-density methane inclusions in the SJT Fm. indicated that the pressure coefficient of the shale section significantly decreased during the Indosinian uplift and erosion stage. The veins in the THB-SP and LSG Fms. were closely related to the oxidation of hydrocarbon gases by TSR (thermochemical sulfate reduction) and the infiltration of atmospheric water, respectively. Therefore, the paleo-fluid in the fractures of Well Yidi2 have integrally recorded the whole geological process including the evolution from oil to gas, the backflow of high-salinity formation water, the upward escape of shale gas, and the process of shale gas reservoirs evolving from overpressure to normal pressure. Considering that Well Yidi2 area is located in a relatively stable tectonic setting, widely distributed fracture veins probably enhance the self-sealing ability, inhibiting the rapid escape of SJT Fm. shale gas. And the rapid deposition of Cretaceous also delayed the loss of shale gas to some extent. The combination of these two factors creates favorable preservation conditions of shale gas, establishing the SJT Fm. as the primary exploration target in this area.