In this work, the mechanical responses and fracture behaviors of pre-heat-treated carbonate rocks during hydraulic fracturing under different confining-axial pressure conditions were systematically investigated. Hydraulic fracturing tests were conducted on carbonate rock samples from the Gaoyuzhuang Formation in Xiongan New Area, China, under equal confining-axial pressures following various temperature pre-treatments. By integrating fluid pressure monitoring, acoustic emission signal acquisition, and three-dimensional fracture morphology scanning, the coupled effects of pre-treatment temperature and stress on fracture pressure, fracture propagation paths, and failure modes were systematically analyzed. The results demonstrate that pre-treatment temperature exerts a significant non-monotonic regulatory effect on rock mechanical behavior. Moderate-low temperatures enhance rock structural integrity, increasing both fracture pressure and the fluid pressure growth rate. In contrast, high temperatures induce micro-fracture networks through thermal stress, resulting in material weakening. Increasing confining-axial pressure not only significantly elevates fracture pressure but also suppresses thermal crack propagation, promoting a transition in failure mode from tension-dominated to shear-dominated behavior. Three-dimensional fracture morphology analysis further reveals that temperature and confining-axial pressure jointly regulate the fluctuation height and spatial complexity of fracture surfaces, with specimens pre-treated at a higher temperature exhibiting peak fracture surface roughness. The research results provide critical experimental evidence for optimizing parameters under coupled temperature-stress conditions in the hydraulic fracturing design of deep carbonate geothermal reservoirs. Document Type: Original article Cited as: Li, P., Tang, C., Wu, X., Liu, Y., Cai, M., Gorjian, M. Mechanical responses and fracture behaviors of pre-heat-treated carbonate rocks during hydraulic fracturing under different confining-axial pressures. Advances in Geo-Energy Research, 2026, 19(3): 250-267. https://doi.org/10.46690/ager.2026.03.05

Underground hydrogen storage in depleted shale gas reservoirs has emerged as a promising option for large-scale energy storage, with feasibility assessments relying on compositional simulations. The fidelity of such simulations hinges on accurate representation of key physicochemical processes, particularly gas adsorption, which governs phase partitioning in shale formations. However, adsorption is often treated deterministically in large-scale simulations, while optimization efforts emphasize operational and geological parameters. This minireview summarizes prevailing compositional simulation workflows and key performance metrics for shale and further synthesizes recent advances and gaps in H₂/ CH₄​ competitive adsorption, highlighting the scarcity and experimental difficulty of multicomponent adsorption data. The propagation of adsorption-related uncertainty to large-scale predictions is further discussed. An illustrative scenario demonstrates that different multicomponent adsorption models can significantly alter the predicted fraction of adsorbed H₂ and the recovery factor. The magnitude of these variations can be comparable to or even exceed improvements achieved through typical operational optimizations. Such discrepancies indicate that adsorption representation is not a non-significant modeling input but a central factor influencing evaluation outcomes. These findings underscore the need to explicitly account for competitive adsorption in assessing underground hydrogen storage in shales. Furthermore, adsorption uncertainty should be systematically quantified and integrated into modeling workflows to secure the high-fidelity of compositional modeling underground hydrogen storage in shales. Document Type: Current minireview Cited as: Lou, Y., Wang, L., Shafiq, M. U., Wang, H., Magsar, O., Meng, X. Modeling fidelity upon competitive adsorption for underground hydrogen storage in depleted shale reservoirs: A minireview. Advances in Geo-Energy Research, 2026, 19(3): 242-249. https://doi.org/10.46690/ager.2026.03.04

Compared with conventional chemical enhanced oil recovery methods, micro/nanofluidbased emulsion systems offer several advantages, including improved mobility control, enhanced stability, and effective modification of interfacial properties, while requiring lower chemical dosage and exhibiting better tolerance to harsh reservoir conditions. This study systematically evaluated the potential of a novel nanofluid-based emulsion as an enhanced oil recovery agent, with emphasis on its rheological behavior, emulsion stability, and interfacial performance. Rheological measurements demonstrate that emulsion viscosity is strongly influenced by the water-to-oil ratio and mixing duration. Systems with low oil content exhibit only modest viscosity changes, whereas increasing oil fraction and mixing time result in pronounced viscosity enhancement, indicating the formation of structured emulsion networks. This viscosity growth contributes to improved emulsion stability, which is further supported by microscopic observations revealing complex multiphase structures. Interfacial characterization shows that the nanofluid-based emulsion effectively lowers the oil-water interfacial tension and induces a strong wettability shift toward water-wet conditions, both of which are favorable for enhanced oil displacement. Microfluidic displacement experiments provide pore-scale evidence that the combined effects of viscosity enhancement, improved emulsion stability, interfacial tension reduction, and wettability alteration lead to efficient mobilization of residual oil. Visual observations confirm in situ emulsion formation within the porous network and improved sweep behavior compared with conventional water injection. Overall, the results highlight the multifunctional role of nanofluid-based emulsions in stabilizing flow, enhancing sweep efficiency, and modifying interfacial dynamics, demonstrating their strong potential as an advanced chemical strategy for enhanced oil recovery applications. Document Type: Original article Cited as: Ovsepian, M., Salami, Y., Karamov, T., Du, D., Dobysh, I., Cheremisin, A., Yuan, C. Multifunctional nanofluids for enhanced oil recovery by simultaneous in situ mobility control and displacement efficiency improvement. Advances in Geo-Energy Research, 2026, 19(3): 231-241. https://doi.org/10.46690/ager.2026.03.03

Assessing the long-term safety of geological CO₂ storage remains a critical technical challenge. CO₂ migration in porous media is governed by the coupling of multiphase flow, capillary trapping, dissolution, geochemical reactions, and geomechanical effects. In addition to geophysical monitoring methods, experimental and mathematical models can estimate CO₂ leakage volumes and associated risks by simulating fluid transportation processes. This perspective offers a comprehensive comparison of the recent experimental studies, physics-based models, and data-driven approaches for evaluating CO₂ storage safety. Laboratory investigations provide fundamental insights into plume evolution and trapping mechanisms. Analytical and semi-analytical models generate rapid storage capability screening. Numerical simulators serve as essential tools for evaluating longterm storage performance. Data-driven methods can accelerate computational-demanding numerical workflows and support uncertainty quantification. Based on the strengths and limitations of the physics-based and data-driven approaches, this paper further identifies future research directions in experimental design and mathematical modeling for CO₂ storage safety assessment. Document Type: Perspective Cited as: Wang, Z., Sun, Q., Li, X., Ampomah, W. Advances and prospects of physics-based and data-driven approaches for CO₂ geological storage safety assessments. Advances in Geo-Energy Research, 2026, 19(2): 97-100. https://doi.org/10.46690/ager.2026.02.07

Variations in brine density are crucial for both CO₂ plume migration and long-term geological CO₂ storage. These variations are primarily controlled by three factors: pressure buildup, CO₂ dissolution, and thermal effects. However, previous models have generally neglected these processes or focused mainly on density variations induced by CO₂ dissolution. This study establishes a comprehensive thermo-hydro-mechanical framework to capture CO₂ migration dynamics in heterogeneous saline aquifers, accounting for brine density variations driven by multiple factors. Eight heterogeneous scenarios, including both high- and low-permeability reservoirs, are constructed to represent realistic subsurface conditions. Results indicate that thermal effects generate a localized cold front in the near-wellbore region, where CO₂ thermodynamic properties are highly temperature-sensitive and differ by several-fold from those of the undisturbed reservoir. Additionally, thermal effects lead to a noticeable decrease in brine density and induce thermal deformation. Brine-density variation is governed primarily by pressure buildup and CO₂ dissolution. The incorporation of CO₂ dissolution in the thermo-hydro-mechanical model shortens the CO₂ plume length by more than 230 m. Pressure buildup is the primary driver for brine density increases in low-permeability reservoirs, whereas CO₂ dissolution plays a more significant role in high-permeability reservoirs. Furthermore, high-permeability reservoirs are more conducive to density-driven convection, where vigorous convective fingering enhances mixing and promotes solubility trapping. Cited as: Jin, A., Park, E., Li, C., Shi, W., Wang Geological CO₂ storage in heterogeneous saline aquifers: Insights into the mechanisms of thermal and density effects. Advances in Geo-Energy Research, 2026, 19(3): 216-230. https://doi.org/10.46690/ager.2026.03.02

Accurate geological modeling of shallow-water delta reservoirs remains challenging due to complex sedimentary architecture and strong heterogeneity. This study develops an advanced modeling technique that integrates geological process understanding with deep learning, with a focus on the accurate representation of channel geometry under multiple data constraints. Field outcrop investigations of the Chang 6 Member in the Ordos Basin were conducted to clarify key geological characteristics and geometric parameters of shallow-water distributary channels. An improved object-based method was employed to effectively generate three-dimensional training datasets capturing typical channel bifurcation and convergence patterns. A conditional progressive generative adversarial network is proposed to incorporate multi-source constraints, including global geological features, well logs, and seismic probability volumes, thereby enabling simultaneous learning of geological patterns and data fidelity. Application to a shallow-water delta reservoir in the Ordos Basin demonstrates that the method produces geologically realistic facies models that honor all available constraints, significantly improving modeling accuracy and computational efficiency. This work provides an innovative and adaptive methodology for intelligent modeling of complex reservoir systems. Cited as: Lu, C., Liu, J., Li, S., Hui, G., Chen, S., Dou, M. Intelligent facies modeling of shallow-water delta reservoirs with conditional generative adversarial networks. Advances in Geo-Energy Research, 2026, 19(3): 201-215. https://doi.org/10.46690/ager.2026.03.01