Herein, the new collected well-testing temperature as well as continuous steady-state temperature logs were achieved for the analysis of deep thermal structural characteristics and current thermal states of various tectonic units in Tarim Basin. Generally, geothermal gradient fluctuates in 14.6-31.1°C/km, the heat flow ranges between 31.6 and 59.2 mW/m² with the average heat flow of 43.2 mW/m², and these values are typical of low heat flow background in Precambrian craton basins. Furthermore, estimated formation temperature spatial distributions at 6~8 km depth are the same and are mainly under the control of basement structural pattern. At 6000 m depth, temperature is 99-188°C, which become 126-242°C and 113-215°C at 7000 m and 8000 m depths, respectively. These findings confirmed that heat flow in Tarim Basin was relatively low with similar geothermal regimes to other Precambrian craton basins around the globe. In addition, 1D theoretical crustal thermal structures in Tarim Basin were established based on the solution of the equation of steady-state heat conduction. The findings revealed that “thermal” lithosphere maximum thickness in Tarim Basin is witnessed in Manjiaer sag. Tazhong uplift thermal state differs from those of Tabei uplift and Manjiaer sag. Tazhong mantle heat flow is 23.9 mW/m², which accounts for 48.8% of surface heat flow. Hotter thermal states of Tazhong uplift generated temperatures as high as ∼690°C in Moho. Tarim Basin heat flow distribution reveals that crustal heat flow plays a more significant role in surface heat flow and possesses typical “hot crust and cold mantle” model thermal structure properties.

Fluid modification critically affects the quality of clastic rock reservoirs. At present, the mechanism of multistage fluid alteration in clastic rock reservoirs under deep burial conditions is still a matter of debate. To solve this problem, this study focuses on the deep clastic reservoirs of the Zhuhai Formation in the Wenchang A Sag of the Zhujiangkou Basin as an example and conducts a series of petrological and geochemical analyses. The results indicate that the fluids that primarily affect reservoir development are hydrothermal fluids and organic acids, and the hydrothermal fluid activity occurred over multiple stages, leading to a diagenetic environment with alternating acidic and alkaline conditions. In this low-permeability reservoir, hydrothermal fluids under acidic conditions were favorable for reservoir development. However, these fluids gradually became alkaline as the reaction proceeded, and under alkaline conditions, carbonate precipitation blocked the pores. In contrast, organic acids had a very positive effect on improving the reservoir. Thus, in this relatively sealed low-permeability reservoir, regions with significant hydrothermal development typically exhibit poor reservoir quality, whereas areas with substantial influxes of organic acids exhibit better porosity and permeability. Furthermore, the order of fluid injection caused substantial variations in reservoir properties. Reservoir areas that first experienced strong hydrothermal injection tend to have very poor properties. In contrast, reservoir areas that first experienced weak hydrothermal fluid influence followed by strong organic acid activity exhibit better properties. The reservoir areas initially improved by organic acids show good connectivity, and any precipitates from later hydrothermal fluids did not accumulate in reservoir pores. As a result, these reservoirs display the best reservoir characteristics. This study defines a model of reservoir development under the combined effects of multiphase fluids and diagenetic environments, which is highly important for evaluating the exploration potential of deep clastic rock reservoirs.

The Shahezi Formation is the main source rock formation in the deep part of the Xujiaweizi Fault Depression. In this study, firstly, based on measured pressure data and logging data, analyzed with methods such as fluid inclusion testing and basin numerical simulation, the pressure evolution history of the Shahezi Formation was systematically reconstructed. Secondly, hydrocarbon generation simulation experiments were carried out under pressures of 45, 70, and 100 MPa to reveal the influence of pressure on the hydrocarbon generation and expulsion process of organic matter. The results showed that the evolution of the pore pressure could be divided into four stages. Prior to the end of the early Cretaceous (~104 Ma), the Xujiaweizi Fault Depression was in a normal-pressure state. In the early Late Cretaceous (104–78 Ma), overpressure was generated in the source rocks due to undercompaction and hydrocarbon generation, which was a stage of rapid pressure increase. In the Late Cretaceous (78–65 Ma), a large amount of gas was generated in the source rocks, and the pressure reached the highest value. From the early Paleogene to the present (65–0 Ma), it has been a stage of slow pressure decrease. The strata have experienced slow uplift, and the pressure has gradually decreased. The effect of high pressure can promote the conversion of heavy hydrocarbon gases in the C1–C5 components to methane, but the promoting effect is limited. In contrast, high pressure has a certain effect on the preservation of liquid hydrocarbon components, and this preservation effect may be caused by the conversion of unstable saturated hydrocarbons to aromatic hydrocarbons.

As a critical component of the global energy portfolio, shale oil has garnered considerable attention, making it essential to understand its enrichment mechanisms and controlling factors. However, accurately evaluating the hydrocarbon potential of shale oil reservoirs remains a significant challenge, particularly in quantifying oil adsorption by clay minerals, for which cost-effective and efficient evaluation methods are still limited. In this study, integrated geochemical and reservoir characterization experiments were conducted to investigate the factors controlling oil adsorption by clay minerals in shale reservoirs. Results show that cation exchange capacity ( Q _v ) is a key parameter—second only to clay content and specific surface area—in assessing oil adsorption capacity. Based on this finding, the classical Waxman–Smits (W–S) model was improved by incorporating a quantitative relationship between Q _v and oil adsorption. The resulting modified W–S model enables rapid, continuous, and quantitative evaluation of oil adsorbed by clay minerals directly from well log data, with predictive accuracy suitable for practical application. This model provides a new approach for evaluating oil adsorption in shale reservoirs and offers practical guidance for reservoir quality assessment, target selection, and optimization of development strategies.