This study presents an integrated, multi-scale laboratory workflow designed specifically for organic-rich shales using multistage solvent extraction. Applied to oil shales of the Bazhenov Formation of varying maturity and lithology, the key unconventional play in Western Siberia, it enables the construction of a robust, volumetric fluid saturation model. The workflow combines mineralogical characterization, conventional core testing, low-field nuclear magnetic resonance relaxometry, high-resolution X-ray computed microtomography, Rock-Eval pyrolysis, and sequential saturates, aromatics, resins, and asphaltenes fractionation following a three-stage solvent extraction protocol. The core analysis following three-step extraction provides new insights into the interplay between lithology, pore system architecture, and fluid distribution mechanisms within tight, organically heterogeneous media. Key findings highlight that conventional methods often underestimate producible hydrocarbons trapped in kerogen nanopores and asphaltene aggregates, necessitating revised nuclear magnetic resonance interpretation approaches. Mechanically induced porosity, varying with organic matter maturity, is identified and linked to hydrocarbon release and matrix deformation. Combining nuclear magnetic resonance and gas porosity measurements provides a rapid, accurate porosity estimation method with minimal sample alteration. Finally, a conceptual fluid physical model is proposed to better interpret nuclear magnetic resonance data and pore-scale fluid dynamics in similar oil shales. The refined methodology of express core assessment significantly improves industry conventional practices by enabling a more precise and physically meaningful quantification of in-situ fluid saturation, including differentiation between bound heavy hydrocarbons and mobile fractions. Beyond advancing the fundamental understanding of fluid saturation and storage capacity in unconventional systems, this framework supports improved reservoir characterization and modeling efforts.

Laboratory modeling of in-situ combustion is crucial for understanding the potential success of field trials in thermal enhanced oil recovery (EOR) and is a vital precursor to scaling the technology for field applications. The high combustion temperatures, reaching up to 480 ℃, induce significant petrophysical alterations of the rock, an often overlooked aspect in thermal EOR projects. Quantifying these changes is essential for potentially repurposing thermally treated, depleted reservoirs for CO₂ storage.

In this study, we depart from conventional combustion experiments that use crushed core, opting instead to analyze the thermal effects on reservoir properties of carbonate rocks using consolidated samples. This technique maintains the intrinsic porosity and permeability, revealing combustion's impact on porosity and mineralogical alterations, with a comparative analysis of these properties pre- and post-combustion. We characterize porosity and pore geometry evolution using low-field nuclear magnetic resonance, X-ray micro-computed tomography, and low-temperature nitrogen adsorption. Mineral composition of the rock and grain-pore scale alterations are analyzed by scanning electron microscopy and X-ray diffraction.

The analysis shows a significant increase in carbonate rocks’ porosity, pore size and mineral alterations, and a transition from mixed-wet to a strongly water-wet state. Total porosity of rock samples increased in average for 15%–20%, and formation of new pores is registered at the scale of 1–30 μm size. High-temperature exposure results in the calcite and dolomite decomposition, calcite dissolution and formation of new minerals—anhydrite and fluorite. Increased microporosity and the shift to strongly water-wet rock state improve the prospects for capillary and residual CO₂ trapping with greater capacity. Consequently, these findings highlight the importance of laboratory in-situ combustion modeling on consolidated rock over tests that use crushed core, and indicate that depleted combustion stimulated reservoirs may prove to be viable candidates for CO₂ storage.