Natural fractures caused by tectonic stress in shale can not only improve the seepage capacity of shale, but also become the migration and loss channel of free gas. Calcite, quartz and other minerals in shale fracture veins record the fluid evolution information of the shale. Through the analysis of different types of fracture cements in the shale of the Silurian–Ordovician Wufeng–Longmaxi Formations in the southern Sichuan Basin, the effect of different fractures on shale gas construction or destruction was clarified. Geochemical investigations included the diagenetic mineral sequences in the hole–cavity veins, paleo-pressure recovery by Raman quantitative analysis, and the environments of diagenetic fluids traced by rare earth elements (REE) signatures. The density, composition, pressure, and temperature properties of CH₄-bearing fluid inclusions were determined by Raman quantitative measurement and thermodynamic simulations to establish the trapping condition of the geo-fluids, and so constrain the periods of gas accumulation. The diagenetic sequences in the fracture veins can be summarized as follows: Cal-I→Qz-II→Cal-III. The Cal-I in the bedding fracture veins crystallized in the late Jurassic (~180 Ma), and originated from hydrothermal origin and diagenetic fluid; the Qz-II veins crystallized in the middle Jurassic (~190 Ma); the Cal-III veins in the high-angle fractures precipitated during the early Eocene (~12 Ma), and derived from atmospheric freshwater leaching. Pore fluid pressure gradually increased. The pressure coefficient of the shale gas reservoir gradually increased to strong overpressure from 160 Ma to 86 Ma. Between 75 Ma and the present day, the pore fluid pressure and the pressure coefficient in the shale reservoirs, having been affected by tectonic activities and strata uplift-erosion, have significantly reduced. Bedding slippage fractures play a constructive role in the enrichment of shale gas, and fracture slip can significantly improve fracture permeability. High-angle shear fractures usually cut through different strata in areas with strong tectonic activity, and destroy the sealing of the shale. The entrapment of primary methane gas inclusions recorded the process of excess reservoir pressure reduction, and indicated the partial loss of shale free gas.

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.

In petroliferous sedimentary basins, the interplay between CO₂ and hydrocarbons exerts a notable influence on hydrocarbon generation and accumulation. This research focuses on the Huangqiao oil and gas reservoir, which is known for hosting the largest CO₂ reserves in China. U–Pb isotopic dating of calcite veins in fractures, carbon and oxygen isotope analyses, along with rare earth element (REE) analysis were applied to elucidate the chronology and origin of inorganic and organic fluids in the studied area. Petrographic observations revealed the presence of various components of fluid inclusions, including gaseous CO₂, gaseous CH₄, CH₄-CO₂ mixtures, and hydrocarbon fluids. Besides, through Raman quantitative measurements and thermodynamic simulations, the density, composition, pressure, and temperature characteristics of CH₄ and CO₂ bearing fluid inclusions were calculated. Based on the entrapment conditions of fluid inclusions and U–Pb dating results, two stages of hydrocarbon charging were identified: an early-Jurassic stage (approximately 200–185 Ma) characterized by mid-maturity oil and CH₄ and an early-Eocene stage (approximately 61–41 Ma) marked by high-maturity oil and CH₄. CO₂ accumulation events were divided into two stages: high-density CO₂ fluid activity during the early Eocene (approximately 59–39 Ma) and low-density CO₂ fluid activity during the Tertiary-Quaternary (approximately 23–4 Ma). Moreover, deep fluid influx into reservoirs led to hydrothermal alteration, as evidenced by anomalously high homogenization temperatures and vitrinite reflectance. CO₂ has an extraction effect on crude oil, where its late entry primarily results in the removal of lighter components, especially CH₄. When high-temperature hydrothermal CO₂ fluid enters the oil reservoir, it accelerates the cracking of crude oil and alters the fluid’s composition. This thermal event also speeds up the source rock’s thermal evolution, leading to extraction, pyrolysis, and gas displacement throughout the reservoir’s development process. This study presents a comprehensive approach for quantitatively studying geological fluids in petroliferous basins of this nature.

Inorganic and organic fluids are widely found in sedimentary basins during oil and gas migration and accumulation. This research investigates two types of sandstone reservoirs with different pressure states and fluid evolution of the Shahejie Formation in the western slope belt of Dongpu Sag. Based on petrographic observations, micro-Raman spectroscopy, and fluorescent spectrometry, petroleum inclusions, CH₄-bearing inclusions, and CO₂-bearing inclusions were discovered in quartz-hosted minerals. The pressure–temperature–time–composition (P–T–t–X) properties of the CH₄ and CO₂ inclusions were obtained by quantitative Raman analysis and thermodynamic models. Minimum trapped pressure was predicted by the thermodynamic modeling of petroleum inclusions. Saffron yellow petroleum inclusions represent an early Oligocene oil-charging event (∼32–30 Ma), and the two kinds of reservoirs were all kept in moderate-overpressure conditions (average pressure coefficient: 1.26). Due to rapid uplift and denudation (Dongying movement) in the middle Oligocene in step II, crude oil degrades into CH₄ and CO₂ (density of CH₄ gas inclusions: 0.1010–0.1339 g/cm³; density of CO₂ gas inclusions: 0.450–0.612 g/cm³) and retains low-maturity (0.67–1.04%) bitumen in situ. Tectonic destruction causes the reservoir to be released to normal pressure. With the reburial of the Es₃ Formation, step II entered the middle stage of oil generation again (average pressure coefficient: 0.90). However, in step I, with secondary hydrocarbons occurring, second-stage oil (performance for pale blue fluorescence in petroleum inclusions) accumulated at ∼12–0 Ma (late Miocene–Pliocene). The second oil charging event in step I remains a reservoir under high-overpressure conditions (average pressure coefficient: 1.67).

Deep-to-ultra-deep marine carbonate reservoirs represent an important frontier for hydrocarbon exploration in the Tarim Basin, yet fluid sources and accumulation processes in the Ediacaran (Sinian) succession remain poorly constrained due to extreme burial depth and complex tectono-thermal evolution. Here, we investigate fracture–vug reservoirs of the Sinian Qigebulake Formation in Well LT3 (Tabei Uplift) using an integrated dataset including petrography and cathodoluminescence, fluid-inclusion microthermometry, fluorescence and Raman spectroscopy, in situ major/trace element analysis and C–O–Sr isotope geochemistry, and LA-ICP-MS carbonate U–Pb dating of authigenic minerals. The paragenetic sequence comprises early dolomite (Dol-I), later dolomite (Dol-II), co-precipitated calcite (Cal-I) and quartz (Qtz-I), and late solid bitumen (Bit). Dolomite veins show PAAS-normalized REE patterns and 87Sr/86Sr ratios (0.70918–0.70984; average 0.70942) comparable to the surrounding Sinian marine wall rocks, indicating precipitation from diagenetic fluids dominated by closed-system water–rock interaction. In contrast, Cal-I displays LREE enrichment, pronounced positive Eu anomalies (δEu = 4.91–7.21), radiogenic ⁸⁷Sr/⁸⁶Sr ratios (0.71161–0.71417; average 0.71256), and negative δ¹⁸O_VPDB values (down to −9.439‰), suggesting a large-scale influx of deep-seated, high-temperature, Sr-rich hydrothermal fluids likely linked to fault-assisted fluid circulation. Fluid inclusions record four hydrocarbon charging episodes, evolving from lower- to higher-maturity oils and ultimately to dry gas. Dol-II hosts pale-yellow to pale-blue oil inclusions, whereas Cal-I and Qtz-I predominantly contain deep-blue oil inclusions and methane-rich gas inclusions (Raman peak near 2917 cm⁻¹). Carbonate U–Pb ages constrain dolomite precipitation to the Middle Ordovician (~468–463 Ma) and hydrothermal-related carbonate filling to the Early Triassic (~247–244 Ma). Collectively, these results support a time-resolved evolution in which early diagenetic fluid circulation in a marine carbonate system was overprinted by a later hydrothermal pulse that modified pore structures and thermal conditions, followed by late-stage deep burial leading to cracking of retained liquids, widespread bitumen formation, and methane charging. This framework provides new information on the constraints for fluid–rock interaction and hydrocarbon evolution in deep marine carbonate successions.

Calcite in hydrocarbon reservoirs records abundant information about diagenetic fluids and environments. Understanding the formation mechanisms of calcite is crucial for predicting reservoir characteristics and hydrocarbon migration. This study identifies the types of authigenic calcite present in the Lower Paleozoic carbonate reservoirs of the Bohai Bay Basin through petrographic analysis, cathodoluminescence, and other experimental methods. By integrating electron probe microanalysis, in situ isotopic analysis, and fluid inclusion studies, we further constrain the source of the diagenetic fluids responsible for the authigenic calcite. The results show that there are at least three types of authigenic calcite in the Lower Paleozoic carbonate reservoirs of the Bohai Sea. Calcite cemented in the syn-depositional-to-early-diagenetic stage displays very weak cathodoluminescence, with δ¹³C and δ¹⁸O and paleo-salinity distributions similar to those of micritic calcite. These features suggest that the calcite was formed during burial heating by sedimentary fluids. Calcite filling fractures shows heterogeneous cathodoluminescence intensity, ranging from weak to strong, indicating multiple stages of cementation. The broad elemental variation and multiple cementation events suggest that the diagenetic fluid sources were diverse. Isotopic data show that samples with carbon isotope values greater than −2.9‰ likely formed through water–rock interaction with fluids retained within the strata, whereas samples exhibiting more negative δ¹³C were formed from a mixed-source supply of strata and mantle-derived fluids. Calcite that fills karst collapse pores exhibits alternating bright and dark cathodoluminescence, strong negative δ¹⁸O shifts, and variability in trace elements such as Mn, Fe, and Co. These characteristics indicate a mixed origin of diagenetic fluids derived from both meteoric freshwater and carbonate-dissolving fluids.