Search Results (60)

The sealing integrity of caprock is crucial for the long-term security of geological CO₂ storage, yet the multifactorial controls on CO₂ breakthrough pressure and its evolution under CO₂ exposure remain insufficiently understood. Using caprock samples from the Ordos Basin, this study combined stepwise pressure elevation experiments, NMR, and CT to investigate the effects of temperature, core length, water saturation, and permeability on CO₂ breakthrough pressure and to reveal associated pore–throat evolution. Results show that breakthrough pressure increases with temperature and water saturation but decreases with permeability and exhibits an approximate linear relationship with core length, with permeability being the dominant controlling factor. Furthermore, CO₂–water–rock reactions lead to a “pore expansion-plugging” pattern, which significantly reduces breakthrough pressure and weakens sealing capacity, though this weakening stabilizes over time. These findings clarify the key controls and time-dependent evolution of caprock sealing, providing a theoretical basis for assessing storage security and predicting long-term efficacy in depleted reservoirs. Full article

This study develops a conceptual framework for characterizing reservoir architecture in multi-component, discrete systems using pressure transient analysis (PTA), aimed at calibrating inflow geometry prior to full-field dynamic simulation for subsurface gas storage applications such as CO₂ and hydrogen. A secondary objective is to identify variations in permeability over time by analyzing flow capacity trends and evaluating the dynamic influence of faults and fractures. The analysis is based on a gas-condensate field comprising seven wells and four zones (A, B, C, D), using integrated dynamic datasets including extended well tests (EWTs), mud loss, production logs, and production data. Detailed interpretation of PX-1’s EWT indicated delayed re-pressurization and persistent under-pressure, suggesting a compartmentalized or transient system with limited gas-in-place connectivity. Four reservoir architecture concepts were developed: (1) lithology-dominated inflow, (2) structurally controlled inflow, (3) discrete, weakly connected compartments, and (4) transient-dominated systems with tight matrix GIIP. These concepts informed four reservoir models: matrix-only (M), areal heterogeneity (A), sparse bodies (B), and sparse networks (S). Application of these models across other wells revealed consistent localized KH (permeability–thickness product) behavior, with all models fitting short-duration data comparably. However, only sparse drainage models (B/S) adequately matched PX-1’s EWT response. PTA results confirm that well tests constrain KH locally but provide limited insight into large-scale reservoir architecture. EWTs may reach ~1 km, while shorter tests are confined to ~200–400 m, typically within one to two simulation grid blocks. This study demonstrates how integrating PTA with multi-scale data improves characterization of naturally fractured, tight carbonate reservoirs and supports reservoir simulation and history matching for hydrogen storage evaluation. Based on reservoir simulations, this study concluded that naturally fractured carbonate gas reservoirs can provide significant storage and injection capacities for underground hydrogen storage. This study exemplifies how to characterize the naturally fractured tight carbonate reservoirs by integrating multi-scale and multi-dimensional data such as PTA. Furthermore, this study assists in gridding for full-field reservoir models, for history matching and quantifying the potential of hydrogen storage in these complex reservoirs. The proposed workflow provides an uncertainty-bounded reservoir characterization framework and should not be interpreted as a complete field-design methodology for hydrogen storage. The modeling does not explicitly couple geomechanical fracture growth, hydrogen diffusion, long-term geochemical reactions, or caprock integrity degradation. Therefore, the presented storage scenarios represent technically feasible cases under defined assumptions. Comprehensive site-specific geomechanical and containment assessments are required prior to field-scale implementation. Full article

Serbia’s energy sector is undergoing structural transformation driven by European climate policies, market volatility, and the need for long-term energy security. In this context, geological storage of energy carriers represents a strategically important option. Depleted gas reservoirs, particularly within the Pannonian Basin, constitute a technically validated subsurface infrastructure suitable for repurposing as multifunctional storage systems for natural gas, CO₂, and green hydrogen. This study analyzes trends in European and Serbian natural gas markets, EU decarbonization targets, and Serbia’s energy balance to assess the feasibility of carbon capture and storage (CCS) and underground hydrogen storage. Key geological parameters governing long-term containment—lithology, effective porosity, permeability, caprock integrity, and structural stability—are evaluated, with emphasis on reservoirs combining favorable properties and proximity to existing infrastructure. Quantitative screening based on reservoir depth (approximately 1000–2500 m), effective porosity (15–25%), permeability (typically >50 mD), verified caprock integrity, and estimated geological storage capacities ranging from 0.17 to 1.25 billion m³ demonstrates that several depleted gas reservoirs in Serbia meet explicit fit-for-purpose criteria for underground storage applications. A comparative analysis of the physical and molecular behavior of H₂, CH₄, and CO₂ in porous media indicates that hydrogen storage is the most sensitive to reservoir integrity. The reported results provide quantitative and qualitative evidence that selected depleted gas reservoirs in Serbia satisfy essential requirements for project-level screening, including reservoir capacity, petrophysical suitability, caprock integrity, and infrastructure accessibility. These findings support the technical readiness of such reservoirs for staged deployment of natural gas storage, CO₂ sequestration, and underground hydrogen storage in the post-2035 energy system. Overall, combined subsurface storage of natural gas, CO₂, and hydrogen in Serbia is technically feasible, economically justified, and strategically relevant within the national energy transition framework. Full article

Geological storage of carbon dioxide in faulted sedimentary basins requires suitability evaluation methods that can address uncertainty, indicator interaction, and limited data availability. This study develops an integrated evaluation framework that combines the Analytic Hierarchy Process, triangular fuzzy numbers, and the Choquet fuzzy integral to assess basin-scale geological carbon dioxide storage suitability. The framework enables structured weight determination, explicit representation of expert uncertainty, and non-additive aggregation of interacting indicators. The evaluation focuses on deep saline aquifers in the Jianghan Basin and is based on seventeen indicators covering geological, structural, hydrogeological, and socio-economic conditions. The assessment integrates seismic interpretation, geological mapping, logging data, and published datasets, and is conducted at the level of tectonic units to support basin-scale screening. The method is applied to the Jianghan Basin using seventeen geological, structural, hydrogeological, and socio-economic indicators. The results indicate that burial depth primarily acts as a threshold condition, whereas caprock sealing capacity, fault system development, and hydrogeological stability dominate suitability differentiation. Interaction analysis reveals pronounced substitution effects among geological indicators, indicating that strong performance in key safety-related factors can compensate for less favorable secondary constraints during early-stage screening. The Qianjiang Sag and Jiangling Sag are identified as the most suitable storage units. The proposed framework provides a transparent and robust tool for basin-scale screening in structurally complex, data-limited sedimentary basins. Full article

Caprock sealing capacity is paramount for the safety and efficacy of geological carbon storage. This study investigates the evolution of mudstone caprock sealing capacity under CO₂–mechanical coupling, integrating experimental rock mechanics with fluid–solid coupling numerical simulations. Laboratory experiments reveal that caprock permeability exhibits strong stress sensitivity, decreasing exponentially with increasing effective stress. The stress sensitivity coefficient is highly dependent on initial pore pressure and porosity, being greatest under low-pore-pressure and high-porosity conditions. Furthermore, permeability loss during loading is partially irreversible due to plastic deformation. Numerical simulations, conducted using an integrated Petrel + Visage + Eclipse workflow, quantify the influence of caprock physical and mechanical properties on sealing capacity during CO₂ injection. The results demonstrate that vertical total stress increases with increasing porosity, Young’s modulus, and permeability, with permeability exerting the most significant control. Conversely, vertical effective stress decreases with increases in these parameters, with porosity causing the largest variation. We conclude that lower caprock permeability and porosity are most critical for enhancing sealing integrity, while a higher Young’s modulus improves mechanical stability. These findings provide a theoretical basis and practical methodology for evaluating caprock sealing capacity and ensuring the secure storage of CO₂. Full article

Offshore saline aquifer CO₂ sequestration relies heavily on the sealing integrity and mechanical stability of mudstone caprocks, yet their responses to supercritical CO₂ (scCO₂) remain inadequately constrained for marine geological settings. Here, we integrate permeability measurements, scCO₂ breakthrough pressure tests, and uniaxial mechanical experiments on natural and reconstituted core samples from the Pearl River Mouth Basin to address this gap. Our results reveal extreme vertical permeability heterogeneity (spanning 10⁻⁶ to 10⁻¹ mD) within Yuehai and Hanjiang Formation caprocks. Critically, permeability and scCO₂ breakthrough pressure are decoupled: breakthrough pressure is controlled by maximum pore-throat radius, while breakthrough time depends on post-breakthrough pore network topology. ScCO₂-brine-rock interactions induce pronounced geomechanical weakening, with uniaxial compressive strength decreasing by up to 71.7% and the elastic modulus reducing, while a substantial increase in Poisson’s ratio signifies a fundamental transition from brittle to ductile behavior. We have developed a comprehensive framework to delineate potential CO₂ migration pathways. Hanjiang Formation Section 1 (represented by sample A3) exhibits exceptional sealing properties, characterized by ultra-low permeability (2.41 × 10⁻⁶ mD), high breakthrough pressure (>16 MPa), and extended breakthrough time (>30 min). These attributes suggest that CO₂ injection into the target saline aquifer at depths between 1470 and 1500 m, situated beneath this interval, can be deemed secure with a high potential for effective long-term containment. These findings provide essential insights for optimizing offshore CO₂ sequestration site selection and injection pressure management to ensure long-term containment security. Full article

This study addresses the challenge of low working gas ratios in China’s underground gas storage (UGS) facilities by optimizing geomechanical evaluations to enable safe pressure increases and capacity expansion. Through mini-fracturing tests conducted at the Liaohe Gas Storage Group, a cross-validated analytical framework was established, integrating the square-root-of-time, Geomechanical (G) function, and flow-back pressure–volume methods. This framework enables precise determination of the dynamic maximum safe pressure, effectively balancing storage efficiency against the risks of fracture and fault activation. The results indicate that the minimum horizontal stress is 37% higher in the caprock than in the reservoir, confirming the integrity of the natural stress barrier. A mere 0.39% discrepancy in interpretation results validates the consistency of the methodology. The derived three-dimensional (D) in situ stress model reveals that the upper sandstone section exhibits 15–20% higher horizontal stress than deeper intervals, acting as a secondary barrier against fracture propagation. Theoretically, we propose a ‘stress differential gradient sealing’ mechanism to explain the buffering effects observed in the sandstone–mudstone transition zone. Practically, we developed a standardized testing protocol for complex geological conditions, which achieved a 15% increase in the maximum safe operating pressure at the Liaohe facility. This study provides critical insights for optimizing gas storage operations. Full article

The aim of this work was to investigate the evolution of the mechanical integrity of the selected offshore oil reservoir during its life cycle. The geomechanical stability of the reservoir formation, including the caprock and base rock, was investigated from the exploitation phase through waterflooding production to the final phase of enhanced oil recovery (EOR) with CO₂ injection. In this study, non-isothermal flow simulations were performed during the process of cold water and CO₂ injection into the oil reservoir as part of the secondary EOR method. The analysis of in situ stress was performed to improve quality of the geomechanical model. The continuous changes in elastic and thermal properties were taken into account. The stress–strain tensor was calculated to efficiently describe and analyze the geomechanical phenomena occurring in the reservoir as well as in the caprock and base rock. The integrity of the reservoir formation was then analyzed in detail with regard to potential reactivation or failure associated with plastic deformation. The consideration of poroelastic and thermoelastic effects made it possible to verify the development method of the selected oil reservoir with regard to water and CO₂ injection. The numerical method that was applied to describe the evolution of an offshore oil reservoir in the context of evaluating the geomechanical state has demonstrated its usefulness and effectiveness. Thermally induced stresses have been found to play a dominant role over poroelastic stresses in securing the geomechanical stability of the reservoir and the caprock during oil recovery enhanced by water and CO₂ injection. It was found that the injection of cold water or CO₂ in a supercritical state mostly affected horizontal stress components, and the change in vertical stress was negligible. The transition from the initial strike-slip regime to the normal faulting due to formation cooling was closely related to the observed failure zones in hybrid and tensile modes. It has been estimated that changes in the geomechanical state of the oil reservoir can increase the formation permeability by sixteen times (fracture reactivation) to as much as thirty-five times (tensile failure). Despite these events, the integrity of the overburden was maintained in the simulations, demonstrating the safety of enhanced oil recovery with CO₂ injection (EOR-CO₂) in the selected offshore oil reservoir. Full article

As industry moves from fossil fuels to green energy, substituting hydrocarbons with hydrogen as an energy carrier seems promising. Hydrogen can be stored in salt caverns, depleted hydrocarbon fields, and saline aquifers. Among other criteria, these storage solutions must ensure storage safety and prevent leakage. The ability of a caprock to prevent fluid from flowing out of the reservoir is, thus, of utmost importance. In this review, the main factors influencing fluid flow are examined. These are the wettability of the caprock formation, the interfacial tension (IFT) between the rock and the gas or liquid phases, and the ability of gases to diffuse through it. To achieve effective sealing, the caprock formation should possess low porosity, a disconnected or highly complicated pore system, low permeability, and remain strongly water-wet regardless of pressure and temperature conditions. In addition, it must exhibit low rock–liquid IFT, while presenting high rock–gas and liquid–gas IFT. Finally, the effective diffusion coefficient should be the lowest possible. Among all of the currently reviewed formations and minerals, the evaporites, low-organic-content shales, mudstones, muscovite, clays, and anhydrite have been identified as highly effective caprocks, offering excellent sealing capabilities and preventing hydrogen leakages. Full article

This research focuses on a methodological study of the fault activation mechanisms associated with carbon dioxide (CO₂) storage, with a focus on determining the underlying geomechanical properties of the caprock. The study uses an analytic hierarchy process (AHP) to prioritize these parameters in order to improve the process for selecting the critical geomechanical design data that underpin the analysis of potential CO₂ storage sites. By integrating expert knowledge through a structured questionnaire, this study extends the process and provides a weighting methodology to provide realistic parameters as input for advanced numerical simulations. The ratings achieved indicated that the injection pressure was the most significant parameter, while fault cohesion was found to be the least significant parameter, having minimal impact on fault displacement. To validate the weighting methodology, a sensitivity analysis was performed using numerical modeling based on these parameters. The results confirmed the accuracy of the weighting methodology, demonstrating that injection pressure is indeed the most critical factor, while fault cohesion has the least impact on displacement. Additionally, the study advances our understanding of key geomechanical parameters, facilitating the development of customized CO₂ injection and containment strategies aimed at reducing risk and enhancing site integrity. Full article

Existing CO₂ leakage risk assessment frameworks for CO₂ capture, geological storage and utilization (CCUS) projects face limitations due to subjective biases and poor adaptability to long-term scale sequestration. This study proposed a dynamic risk assessment method for CO₂ leakage based on a timeliness analysis of different leakage paths and accurate time-dependent numerical simulations, and it was applied to the first CO₂ enhanced gas recovery (CCUS-EGR) pilot project of China in the Maokou carbonate gas reservoir in the Wolonghe gas field. A 3D geological model of the Maokou gas reservoir was first developed and validated. The CO₂ leakage risk under different scenarios including wellbore failure, caprock fracturing, and new fracture activation were evaluated. The dynamic CO₂ leakage risk of the CCUS-EGR project was then quantified using the developed method and numerical simulations. The results revealed that the CO₂ leakage risk was observed to be the most pronounced when the caprock integrity was damaged by faults or geologic activities. This was followed by leakage caused by wellbore failures. However, fracture activation in the reservoir plays a neglected role in CO₂ leakage. The CO₂ leakage risk and critical risk factors dynamically change with time. In the short term (at 5 years), the project has a low risk of CO₂ leakage, and well stability and existing faults are the major risk factors. In the long term (at 30 years), special attention should be paid to the high permeable area due to its high CO₂ leakage risk. Factors affecting the spatial distribution of CO₂, such as the reservoir permeability and porosity, alternately dominate the leakage risk. This study established a method bridging gaps in the ability to accurately predict long-term CO₂ leakage risks and provides a valuable reference for the security implementation of other similar CCUS-EGR projects. Full article

This study focuses on the genesis mechanism of thermal anomalies in the southwestern part of the Anan Depression in the Erlian Basin. Based on magnetotelluric 3D inversion data, a high-resolution electrical resistivity structure model was constructed, revealing the spatial configuration of deep heat sources and thermal pathways. The main conclusions are as follows: (1) Magnetotelluric 3D imaging reveals an elliptical low-resistivity anomaly (Anomaly C: 20 km × 16 km × 5 km, 0–5 Ωm) at depths of ~10–15 km. This anomaly is interpreted as a hypersaline fluid (approximately 400 °C, ~1.5% volume fraction, 3–5 wt.% NaCl), acting as the primary heat source. (2) Upward migration along F1/F3 fault conduits (10–40 Ωm) establishes a continuous pathway to mid-depth reservoirs D1/D2 (~5 km, 5–10 Ωm) and shallow crust. An overlying high-resistivity caprock (40–100 Ωm) seals thermal energy, forming a convective “source-conduit-reservoir-cap” system. (3) Integrated seismic data reveal that heat from the Abaga volcanic melt supplements Anomaly C via conduction through these conduits, combining with mantle-derived heat to form a composite source. This research delineates the interacting genesis mechanism of “deep low-resistivity heat source—medium-low resistivity fault conduit—shallow low-resistivity reservoir—relatively high-resistivity cap rock” in the southwestern A’nan Sag, providing a scientific basis for optimizing geothermal exploration targets and assessing resource potential. Full article

CO₂ geological storage (CGS) is critical for mitigating emissions in hard-to-abate industries under carbon neutrality. However, its implementation faces significant challenges. This paper examines CO₂-trapping mechanisms and proposes key safety measures: the continuous monitoring of in situ CO₂ migration and formation pressure dynamics to prevent remobilization, and pre-injection lithological analysis to assess mineral trapping potential. CO₂ injection alters reservoir stresses, inducing surface deformation; understanding long-term rock mechanics (creep, damage) is paramount. Thermomechanical effects from supercritical CO₂ injection pose risks to caprock integrity and fault reactivation, necessitating comprehensive, multi-scale, real-time monitoring for leakage detection. Geostatistical analysis of well log and seismic data enables realistic subsurface characterization, improving numerical model accuracy for risk assessment. This review synthesizes current CGS knowledge, analyzes technical challenges, and aims to inform future site selection, operations, and monitoring strategies. Full article

Underground hydrogen storage (UHS) in shale and tight reservoirs offers a promising solution for large-scale energy storage, playing a critical role in the transition to a hydrogen-based economy. However, the successful deployment of UHS in these low-permeability formations depends on a thorough understanding of the geomechanical and geochemical factors that affect storage integrity, injectivity, and long-term stability. This review critically examines the geomechanical aspects, including stress distribution, rock deformation, fracture propagation, and caprock integrity, which govern hydrogen containment under subsurface conditions. Additionally, it explores key geochemical challenges such as hydrogen-induced mineral alterations, adsorption effects, microbial activity, and potential reactivity with formation fluids, to evaluate their impact on storage feasibility. A comprehensive analysis of experimental studies, numerical modeling approaches, and field applications is presented to identify knowledge gaps and future research directions. Full article

This study presents the first integrated, basin-scale analysis of helium distribution and its geological controls within the Ordos Basin, one of China’s most prospective cratonic gas provinces. Through comprehensive sampling and experimental analysis of the helium content in natural gas, combined with high-resolution gravity and magnetic data processed using the normalized vertical derivative of the total horizontal derivative (NVDR-THDR) method, we reveal significant spatial heterogeneity in helium enrichment. The results show that helium concentrations are generally higher along the basin margins and structurally complex zones, while central areas are relatively depleted. Helium primarily originates from the radioactive decay of uranium (U) and thorium (Th) within metamorphic and magmatic basement rocks. Fault systems act as efficient vertical migration pathways, enabling deep-sourced helium to accumulate in structurally and stratigraphically favorable traps. This study proposes a new enrichment mode, “basement-sourced helium generation, fault-mediated migration, and caprock-controlled preservation”, which highlights the synergistic roles of basement lithology, deep-seated faults, and sealing capacity in controlling helium distribution. This model is supported by the observed alignment of high helium concentrations with zones of strong basement magnetism and major fault intersections. These findings advance our understanding of helium accumulation mechanisms in stable cratonic settings and provide a predictive framework for helium exploration in similar geological contexts worldwide. Full article