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.
The mechanical response of heterogeneous rock masses under multi-field coupling conditions is central to geo-energy development and underground storage. This study synthesizes key insights from Session 49 of the second u201CInternational Geo-Energy Frontier Forumu201D, entitled u201CMulti-field Coupled Mechanics of Deep Heterogeneous Rock Massesu201D. Twenty-two experts and scholars presented their recent advances in heterogeneous-structure characterization, laboratory testing, mechanical mechanisms, and engineering applications. The discussion was organized around the experimental characterization of deep heterogeneous rocks, mechanistic links between local damage and fracture-network development under coupled thermal-hydraulic-mechanical-chemical conditions, and implications for energy development and underground storage. Perspectives distilled from these themes may provide useful guidance for optimizing stimulation schemes, assessing containment safety, and evaluating long-term reliability in deep geo-energy operations.
Shale oil and gas differ greatly in reservoir characteristics and accumulation mechanisms. This work compares the enrichment characteristics of marine and continental shale oil and gas, and systematically summarizes targeted green-efficient exploitation technologies for shale resources. Two quantitative theoretical models are established, namely the multi-field coupling accumulation model for shale gas and the nanoconfinement synergistic conversion model for shale oil. The integrated framework provides theoretical support for the differentiated low-carbon development of shale oil and gas and facilitates the achievement of dual carbon goals. Future research directions regarding mechanism study, technological innovation, and green evaluation systems are also prospected.
With increasing depths in coal mining, water injection into coal seams has become a crucial technology to enhance coalbed methane recovery, suppress dust, and prevent gas outbursts under high stress and geothermal conditions. Given this background, this study aims to elucidate the dynamic behavior of water injection, migration and evaporation in coal. To investigate pore-fracture connectivity and moisture transport mechanisms, coal samples drilled and collected from a coal mine in Inner Mongolia, China, were analyzed using a combination of multi-scale characterization techniques, enabling the characterization of the relationship between pore structure connectivity and water transport behavior. Nuclear magnetic resonance, computer tomography, and mercury intrusion porosimetry were jointly utilized to explore the pore structure at different scales, and nuclear magnetic resonance was further used for real-time online water injection monitoring, allowing the dynamic observation of water migration and distribution within the samples. The results indicate that borehole drilling significantly enhances permeability and connected porosity, controlling both injection rate and maximum water uptake. Moreover, water transport is governed by pore structure at different scales, with fine pores influencing adsorption and larger pores facilitating flow. Evaporation under elevated temperatures proceeds from rapid free-water loss to slower bound-water desorption, with borehole presence having a minimal effect. These findings provide key insights into the multi-scale control of water dynamics and offer a theoretical and experimental basis for optimizing coalbed water injection strategies in deep, high-temperature environments.
Natural fractures affect hydraulic fracture propagation, pressure diffusion, casing integrity and stimulation efficiency in deep unconventional reservoirs. Conventional Mohr-Coulomb stability analysis usually assumes a fixed or weakly updated stress field, limiting its ability to capture evolving geomechanical perturbations during hydraulic fracturing. This study proposes a dynamic Mohr-Coulomb stability evaluation framework based on stress superposition induced by hydraulic fractures. Laboratory-constrained mechanical parameters, three-dimensional geomechanical modeling, induced stress redistribution and dynamic Mohr circle updating are integrated and tested using continental and marine shale cases. The results show that hydraulic fracturing increases all three principal stresses, with the minimum horizontal principal stress showing the strongest response. The effective stress superposition range is mainly limited to adjacent fracturing stages, indicating a localized but mechanically significant interaction zone. Static analysis reveals a nonlinear relationship between critical pore pressure increment and fracture approach angle, defining a friction-controlled stability window. Dynamic analysis further incorporates variations in principal stress, pore pressure, maximum horizontal stress orientation and fracture cohesion. The predicted activation risk zones agree with field observations from treatment pressure responses and microseismic data. Pumping rate optimization reduces activation risk by weakening stress and pore pressure perturbations near critically oriented natural fractures. The proposed framework provides a quantitative basis for diagnosing natural fracture activation, mitigating casing deformation and optimizing fracturing parameters in deep fractured shale reservoirs.
The intermittency and volatility of renewable energy sources critically constrain their large-scale grid integration, positioning underground energy storage as an indispensable solution for the energy transition. This editorial provides a comprehensive overview of major underground energy storage technologies-including salt cavern compressed air energy storage, depleted gas reservoir storage, underground hydrogen storage, geological CO2 sequestration, and underground thermal energy storage. For each modality, we identify key challenges such as multi-physics coupling, caprock integrity, geochemical reactivity, and long-term reservoir stability. We further highlight cross-cutting frontiers including digital rock physics, artificial intelligence-driven characterization, and digital twin technologies. Finally, we issue a formal call for contributions that bridge fundamental mechanisms with field-scale engineering practice, reaffirming the commitment of Advances in Geo-Energy Research to advancing geo-energy science for a sustainable future.
Deep-sea natural gas hydrates represent a vast energy frontier, yet commercial extraction triggers complex multiphysics couplings, posing significant geomechanical and environmental hazards. This perspective synthesizes recent advances in elucidating multiscale triggers of reservoir instability and gas leakage. Leveraging three-dimensional digital rock physics, the impact of microstructural evolution on nonlinear flow is investigated, with specific focus on hydrate morphology transitions and fines-migration-induced clogging. Geomechanical hazards are interpreted through novel stress-partitioning constitutive models coupled with acoustic-mechanical monitoring. Furthermore, the integration of multidimensional geophysical monitoring with hybrid data-driven and physics-based fusion methodologies offers a novel pathway for predicting coupled hydro-mechanical behaviors and enables real-time adaptive management. By bridging the scale gap from molecular kinetics to reservoir-scale responses, a comprehensive framework is outlined for safe and predictable hydrate production while mitigating environmental leakage risks.
Integrating physical mechanisms with data-driven methods overcomes the limitations of purely data-driven artificial intelligence and purely mechanism-based models. Purely data-driven approaches suffer from poor interpretability and weak generalization under sparse data, while purely physics-based models are computationally expensive and struggle with complex nonlinearities. This work highlights advances in the physics-constrained, data-driven dual paradigm across petroleum engineering: mechanismu2013artificial intelligence fusion via Bayesian networks provides traceable hydrocarbon spatial distribution predictions; knowledgeu2013data-driven modelling ensures geological realism; and collaborative physicsu2013data fault diagnosis enhances well monitoring under noise. These advances demonstrate that deep fusion of domain knowledge, physical laws, and multi-source data is essential for creating interpretable, reliable, and efficient intelligent systems for complex subsurface resource development.
Organic-rich shales present significant potential for underground hydrogen storage, yet our understanding of the interactions of H2 with CH4 and CO2 in kerogen-hosted nanopores remain insufficient. This study constructs and validates macromolecular models of high-maturity and overmature kerogens via combining solid-state carbon-13 nuclear magnetic resonance spectroscopy, Fourier-transform infrared spectroscopy, and X-ray photoelectron spectroscopy. Grand canonical Monte Carlo and molecular dynamics simulations are performed, which reveal that kerogen maturity controls the competitive adsorption and diffusion of methane/hydrogen and carbon dioxide/hydrogen mixtures by regulating nanopore structure and surface chemical heterogeneity. Compared with high-maturity kerogen, overmature kerogen shows stronger confinement and a more pronounced near-surface enrichment of CH4 and especially CO2, which reduces the effective storage space available for H2. Mechanistically, CH4/H2 competition is driven by van der Waals interactions, whereas CO2/H2 competition is dominated by stronger electrostatic and inductive interactions, establishing a thermodynamic affinity order. The radial distribution functions and interaction energies are measured, which confirm that CH4 and CO2 monopolize high-energy surface sites, relegating H2 to a weakly adsorbed, bulk-like state. Although H2 exhibits the weakest adsorption affinity, its high mobility suggests a stronger migration tendency and potential leakage risk, which should be considered when evaluating long-term containment security during underground hydrogen storage. Overall, this study reveals that maturity-controlled coupling exists between kerogen structure, competitive adsorption and gas transport, providing molecular-scale insights into hydrogen storage security, injectivity, leakage risk, and recovery in organic-rich shale reservoirs.
The transition to a low-carbon energy system and the emergence of a hydrogen economy have increased the need for large-scale, reliable subsurface storage of carbon dioxide, hydrogen, and natural gas. Selecting suitable storage sites requires balancing geological, technical, environmental, economic, and social criteria, while accounting for the distinct physical and chemical behaviors of each gas and the intended service. This paper adopts a unified, gas-aware framework to synthesize site-selection criteria and decision-support methods for subsurface gas storage across the principal geological options: deep saline aquifers, depleted hydrocarbon reservoirs, and salt caverns. The study examines decision-making approaches ranging from conventional multi-criteria decision-making and fuzzy extensions to Geographic Information System-based spatial analysis, reservoir simulation, and emerging machine-learning techniques for large-scale screening and uncertainty quantification and mitigation. Drawing on global case studies, it identifies methodological limitations, gas-specific knowledge gaps, and data challenges that constrain confident site selection, particularly for hydrogen storage in deep saline aquifers and depleted reservoirs, including reactivity and microbial consumption risks, purity and mixing constraints, and cushion-gas economics. Future directions emphasize the need for integrated, explainable, and adaptive decision frameworks tailored to gas-specific behaviors and storage contexts; expanded large-scale H2 demonstrations in saline aquifers and depleted reservoirs; tighter coupling of monitoring, modeling, and decision tools throughout the project lifecycle; and regulatory frameworks that clarify long-term liability and strengthen public engagement and trust. Collectively, these insights provide a structured basis for developing robust and transparent decision pathways for strategic subsurface storage in support of energy-transition objectives.
Premium standalone sand screens must limit sand production while preserving productivity, yet most erosion- and plugging-centred studies do not quantify how a stabilised filter-bed transfers hydraulic loading into stresses on woven wires. This study quantifies sustained normal and shear loading on a plain-weave standalone screen beneath stabilised sand filter-beds using an immersed boundary computational fluid dynamics-discrete element framework under increasing imposed pressure drop. Screen-surface stresses were evaluated over the loaded screen area for the whole screen and for interior and perimeter reporting zones using area-time-weighted distributions. The results show a clear monotonic strengthening of the stabilised loading state as pressure drop increased. Typical loading rose in both the normal and shear components, with the normal component remaining dominant throughout. The loaded-area fraction increased only modestly, whereas the mean stress over the loaded area increased much more strongly. This indicates that higher pressure drop amplified stress intensity within already engaged regions more than it expanded the area carrying load. The upper tail of the stress distribution also strengthened, which shows that increasing pressure drop intensified not only the typical loading state but also the most severe loading regime. Hotspot maps further showed persistent wire-scale organisation within each stabilised window, together with perimeter-associated amplification in the normal upper tail under the present configuration. These findings provide mechanics-based loading descriptors that can support screen qualification procedures and operating-envelope assessment under stabilised filter-bed loading.
Multiscale energy and mass transport processes constitute the fundamental scientific foundation for sustainable geo-energy development and carbon neutrality. This perspective synthesizes cutting-edge advances in the field into three transformative thematic areas: thermodynamically consistent pore-scale modeling with robust numerical schemes that embed fundamental physical laws into mathematical formulations; molecular-scale insights and data-driven acceleration techniques bridging nanoscopic interfacial phenomena to reservoir-scale engineering; and coupled multiphysics-artificial intelligence frameworks for hydrogen infrastructure safety and supercritical CO2 geothermal systems. Recent research reveals a paradigm shift toward living digital twins that integrate rigorous mathematical physics, multiscale computing, and artificial intelligence, charting a clear course toward carbon-neutral energy systems.
The autothermic pyrolysis in-situ conversion process of oil shale has emerged as a vital development direction due to its advantages of environmental friendliness and low cost. However, previous studies predominantly employed constant injection and production parameters, which often result in inefficient compression energy injection and formation oxidation losses, thereby limiting further improvements in energy efficiency and oil production. To address these issues, this study establishes a dynamic optimization model for injection-production parameters in the autothermic pyrolysis in-situ conversion process of oil shale, developing a dynamic control methodology for gas injection rate and oxygen content to enhance the economic viability and feasibility of the process. The results indicate that under the optimal combination of gas injection u2013 adjustment time, decay rate, and terminal flow rate u2013 the steady-state phase during late production can significantly reduce input compression energy and inhibit hydrocarbon oxidation losses, ultimately leading to a substantial increase in the peak energy efficiency and cumulative oil production. Furthermore, by synergistically regulating oxygen content and injection rate during the early production stage, the compression energy can be further reduced, ultimately elevating the energy efficiency to approximately fourteen, demonstrating the technical feasibility for industrial-scale production. These findings and the identified key parameters provide crucial theoretical and technical support for the large-scale application of the autothermic pyrolysis in-situ conversion technology for oil shale.
The accurate prediction of shale oil production requires strong coupling between flow and geomechanics. However, traditional models often overlook the dynamic permeability damage induced by in-situ stress variations. To address this issue, our study establishes a fully coupled numerical simulation framework based on the virtual element method. This framework directly employs unstructured polyhedral grids generated by geological modeling software. This approach provides a distinct advantage over conventional methods, which rely on mesh reconstruction and exhibit severe distortion problems under large deformations. The model is validated using production data from a real field block, demonstrating the ability to accurately reproduce complex flow regime transitions and stress-induced production decline. Quantitative analysis identifies the Biot modulus as a key parameter governing reservoir stress sensitivity. Lower modulus values directly lead to substantial and sustained permeability damage. High fracture conductivity provides an initial productivity enhancement; however, it also accelerates stress redistribution around fractures that can cause severe localized permeability impairment in the vicinity of fracture roots over a relatively short production period. This work establishes a new integrated simulation model that couples geomechanical feedback with fluid flow, providing a quantitative engineering basis for effectively optimizing pressure-controlled production strategies and hydraulic fracturing design in shale oil reservoirs.
Hydrogen generation through serpentinization reactions in peridotite formations under high temperature conditions represents a promising avenue for subsurface hydrogen production. However, the thermal energy in the formation environment have not been sufficiently considered. To integrate hydrogen production with thermal energy development, this study develops a thermo-hydro-chemical coupled numerical model, which is used to investigate hydrogen-thermal co-development in hydraulically fractured peridotite. Given that the hydrogen-thermal co-development process involves fluid flow, heat transfer and serpentinization reactions, the governing equations are formulated based on Darcy flow and energy conservation equations, with serpentinization kinetics incorporated through the reactive source terms. To evaluate hydrogen production and thermal energy recovery under varying formation and injection fluid temperatures, the coupled system is solved numerically. The results show that under high geothermal temperature conditions, continuous high-temperature injection combined with moderate natural fracture development can sustain stable high production during long-term operation. When the contribution of thermal energy is neglected, the total system energy output decreases significantly, highlighting the necessity of hydrogen-thermal co-development. This study further identifies the optimal injection temperature range under high geothermal conditions. Under normal geothermal conditions, hydrogen production is limited by reaction temperature, and high-level production cannot be maintained solely through thermal stimulation. Sensitivity analysis reveals that reaction kinetics are the dominant factor controlling system hydrogen productivity, and enhancing them can increase hydrogen production by nearly an order of magnitude. This work establishes a quantitative framework for artificial hydrogen generation and provides theoretical guidance for engineering design and the operational parameter optimization of hydrogen-thermal co-development systems.
Shale oil and gas development is shifting from single stimulation methods toward integrated recovery strategies that combine flow-mechanism understanding, enhanced oil recovery, and carbon utilization and storage. Based on the discussions in Session u201CShale Oil and Gas Flow Mechanisms and Enhanced Oil Recoveryu201D of the second u201CInternational Geo-Energy Frontier Forumu201D, this work summarizes recent advances in thermally assisted CO2 huff-n-puff, supercritical CO2 flow and multiscale CO2 foam simulation, in-situ upgrading and thermal conversion, micro/nanobubble injection, dual geological-engineering sweet-spot identification, and shut-in optimization. The major bottleneck is no longer the lack of individual stimulation methods, but the insufficient integration among pore-scale mechanisms, fracture-matrix interactions, field-scale simulation, and carbon storage accounting. Future research should focus on mechanism-informed pilot design, lithology-specific upscaling models, CO2-thermal-chemical coupled processes, and standardized evaluation workflows linking recovery efficiency with carbon sequestration performance.
