Hydrothermal activity is widespread in sedimentary basins, but its dual effects (chemistry and temperature) on shale reservoirs are rarely discussed. In this research, we systematically collected 33 well core samples from Q1 to Q9 units in Gulong Sag, Songliao Basin, and analyzed them using a variety of analytical techniques, including a field emission scanning electron microscopy (FE-SEM), an energy-dispersive spectrometer (EDS), X-ray diffraction (XRD), and stable C-O isotopes. Combined with the collected vitrinite reflectance (Ro), total organic carbon (TOC), and soluble hydrocarbon content data, which is the sum of free oil (pyrolysis S1) and sorb oil content (pyrolysis S2), the results show that (1) Q4 and Q8 units have large amounts of hydrothermal minerals, and its C-O isotope obviously shifts to negative, which implied those units are the main hydrothermal fluid influence area; (2) the hydrothermal activity occurred in the late depositional period of Q1–Q9 units such that its geochemistry has little effect on the proliferation of algae blooms, but its high temperature calculated by δ¹⁸O temperature formulas (around 208 °C) promoted the organic matter maturation process around Q4 and Q8; and (3) the overpressure caused by hydrothermal activity protected the shale reservoir and minimized the decrease in mineral reservoir brittleness index caused by hydrothermal fluid influence. We suggest that the shale reservoir affected by hydrothermal fluid will become a good geology “dessert”, and its upper and/or lower bounds can form an engineering “dessert” due to the precipitation of large amounts of brittle carbonate minerals.

In this work, Huadian oil shale was extracted by subcritical water at 365 °C with a time series (2–100 h) to better investigate the carbon isotope fractionation characteristics and how to use its fractionation characteristics to constrain the oil recovery stage during oil shale in situ exploitation. The results revealed that the maximum generation of oil is 70–100 h, and the secondary cracking is limited. The carbon isotopes of the hydrocarbon gases show a normal sequence, with no “rollover” and “reversals” phenomena, and the existence of alkene gases and the CH₄-CO₂-CO diagram implied that neither chemical nor carbon isotopes achieve equilibrium in the C-H-O system. The carbon isotope (C₁–C₃) fractionation before oil generation is mainly related to kinetics of organic matter decomposition, and the thermodynamic equilibrium process is limited; when entering the oil generation area, the effect of the carbon isotope thermodynamic equilibrium process (CH₄ + 2H₂O ⇄ CO₂ + 4H₂) becomes more important than kinetics, and when it exceeds the maximum oil generation stage, the carbon isotope kinetics process becomes more important again. The δ¹³${\mathrm{C}}_{{CO}_2-{CH}_4}$ is the result of the competition between kinetics and thermodynamic fractionation during the oil shale pyrolysis process. After oil begins to generate, δ¹³${\mathrm{C}}_{{CO}_2-{CH}_4}$ goes from increasing to decreasing (first “turning”); in contrast, when exceeding the maximum oil generation area, it goes from decreasing to increasing (second “turning”). Thus, the second “turning” point can be used to indicate the maximum oil generation area, and it also can be used to help determine when to stop the heating process during oil shale exploitation and lower the production costs.

Spontaneous imbibition (SI) is a fundamental mechanism for improving the production efficiency of tight sandstone reservoirs. Matrix characteristic plays important roles in the SI process, but how these factors affect SI and the limit pore‐throat size of effective driving force in the tight sandstone of the Tuha Basin has not been firmly established. Thus, a series of experiments (FE‐SEM, QEMSCAN, XRD, CT, and SI) of four tight sandstone core samples were conducted under laboratory conditions in the Tuha Basin. The results show that quartz and plagioclase feldspar are the main detrital minerals, while illite and illite/smectite (I/S) are the predominant clay minerals of those sandstone samples, and they have a micro‐nano (10 μm) pores, but the micro‐nano pore performance disconnected, and during SI process, fluid enters small and meso‐macro‐size pores simultaneously. However, small pores play a dominant role in the initial stage (with steep imbibition slopes), while meso‐macro pores predominate in the second stage (with shallow imbibition slopes), and the limit pore‐throat value of the tight sandstone is around 9.1 μm in the Tuha Basin, beyond which the SI will be weakened. Though the mineral composition and its wettability will be changed with fluid environment (especially for clay minerals), the small pores (formed by clay minerals) always play a dominant role than meso‐macro‐size pores (mainly formed by quartz and plagioclase feldspar) in SI process. These observations can improve our understanding of fluid–reservoir interaction in the Tuha Basin’s tight sandstone reservoir and provide guidance for improving oil and gas recovery.