Geological Storage Research Articles

Permeability evolution of sandstone caprock transverse fractures during intermittent CO2 injection in coal-bearing strata

The caprock of coal-bearing strata plays a critical role in CO2 geological storage, with the presence of fractures posing a heightened risk of CO2 leakage. The cyclic effects of CO2 injection and in situ stress influence the permeability of caprock fractures. However, the combined impact of CO2 and in situ stress on fracture permeability remains uncertain. This study conducted cyclic seepage experiments under varying amplitude stresses on fractured sandstone samples soaked in ScCO2 for different times (0, 15, 30, and 60 days). The microstructural characteristics of the fractured sandstone surfaces were analyzed using scanning electron microscopy and x-ray diffraction. The experimental results indicated that soaking in ScCO2 reduces sandstone fracture permeability, but the extent of this reduction is nonlinearly related to the soaking time. During the stress cycling process, due to the effect of plastic deformation, the permeability of sandstone fractures decreases with increasing cyclic amplitude and remains relatively constant with decreasing cyclic amplitude. At the same cyclic amplitude, the permeability of sandstone fractures initially increases and then decreases with prolonged soaking time. The impact of ScCO2 and stress cycling on the permeability of sandstone fractures is the result of a series of combined chemical–mechanical effects. The combined effects of chemical dissolution and mechanical degradation significantly influence the permeability of sandstone fractures, and this impact is notably time-dependent. During short-term soaking, geochemically induced changes in the surface structure of fractures cause fluctuations in permeability, while in long-term soaking, the combined chemical–mechanical effects promote a reduction in fracture permeability.

Feasibility of carbon dioxide geological storage in abandoned coal mine: A fully coupled model with validated multi-physical interactions

It has gained wide attention that Carbon dioxide (CO2) is to be injected into abandoned coal mines for geological storage of CO2-enhanced coalbed methane recovery. Although abundantly evidences in literature indicate that the injection of CO2 will cause lots of interactions among the mechanical characteristics of coal and the properties of CO2 flow, further studies on these multi-physical interactions are still necessary. In this work, a series of laboratory experiments to elucidate the multi-physical interactions of CO2 adsorption, softening effect of coal and the non-Darcy gas flow were conducted. Based on the experimental results, theoretical and empirical models to describe these coal-CO2 interactions were meticulously proposed and validated, the results turned out to be satisfactory. Consequently, the compressive strength and elasticity modulus of coal decrease exponentially with the increased injection CO2 pressure. The gas flow in coal obeys the Izbash non-Darcy model, and coal permeability can be well modified by the volumetric stress. By taking these coal-CO2 interactions into account, this study established of a fully coupled model for coal deformation and CO2 conservation. The model was then implemented into the numerical simulations of CO2 storage in abandoned coal mine by using the finite element method. A series of scenario-based numerical simulations was conducted to investigate the feasibility and limitation of CO2 storage in abandoned coal mine. The conducted experiments, models and numerical simulation will offer implications on the multi-physical interactions between coal and gas especially in CO2 storage in abandoned coal mines.

Techno-economic-environmental study of CO2 and aqueous formate solution injection for geologic carbon storage and enhanced oil recovery

As carbon capture, utilization, and storage (CCUS), carbon-dioxide enhanced oil recovery (CO2 EOR) has inherent shortcomings, such as inefficient oil recovery and carbon storage, and low storage security with mobile CO2. This paper presents a techno-economic-environmental analysis of using formate species, a product of CO2 electrochemical reduction, as an alternative carbon carrier for sequestration and EOR in a carbonate oil reservoir in the Gulf of Mexico Basin. CO2 injection, water-alternating-CO2 injection, and aqueous formate solution injection were compared using a compositional reservoir simulation model and an economic calculator. Formate solution injection yielded greater levels of oil recovery and net carbon storage, where the carbon-bearing species resided in the dense aqueous phase without having to rely on petrophysical trapping mechanisms (structural and capillary). The enhanced oil production, net carbon storage, and storage security can be promoted by providing formate-based CCUS with more incentives (e.g., greater tax credit) in comparison to CO2-based CCUS for EOR and the manufacture of chemicals and products. In establishing carbon storage incentive policies and regulations, policymakers should include alternative carbon carriers.

Caprock sealing integrity and key indicators of CO2 geological storage considering the effect of hydraulic-mechanical coupling: X field in the Bohai Bay Basin, China

Caprock sealing efficiency is an essential guarantee for the long-term safety and stability of CO2 geological storage (CCS). However, the uncertainty in the physical and mechanical properties of deep formations poses challenges to accurately predict the risks of CO2 leakage resulting in CO2 breakthrough or caprock fracture. This study aims to address the issue of imperfect key indicators for caprock sealing by focusing on the CCS project in the Bohai Bay Basin, China. A hydraulic-mechanical (HM) coupling program without considering multiphase flow and the chemical reactions is secondary developed based on the finite element software ABAQUS. Furthermore, a three-dimensional finite element numerical model is established for the analysis of HM coupling, with pore pressure increment (∆PP), Coulomb failure stress (∆CFS) and displacement (U) as evaluation criteria. The Tornado analysis and response surface analysis are employed to analyze the impact of 17 indicators on the caprock sealing, including caprock thickness, burial depth, reservoir and caprock permeability parameters, and mechanical parameters. Subsequently, key performance indicators for caprock sealing are determined. The research results indicate that the reservoir permeability, injection rate, caprock permeability, caprock Young's modulus, caprock internal friction angle, caprock Poisson's ratio, and caprock burial depth are key indicators of caprock sealing capability. The reservoir permeability has a greater impact sensitivity compared to the caprock permeability. Pore pressure and displacement increase with increasing in reservoir permeability. The caprock's resistance to deformation and fracturing increases with increasing in Young's modulus and Poisson's ratio of caprock. This study provides valuable insights for evaluating caprock sealing during CO2 storage in saline aquifers.

Hydrogen and Cushion Gas Adsorption-Desorption Dynamics on Clay Minerals.

Transitioning toward a hydrogen (H2)-centric energy paradigm necessitates understanding the adsorption properties of clay minerals, essential constituents of reservoirs and caprocks, for efficient geological H2 storage. This study examines the adsorption characteristics of H2 on various clay minerals (montmorillonite, illite, chlorite, kaolinite, and sepiolite) at different temperatures and the adsorption of cushion gases (N2, CH4, and CO2) under reservoir conditions (313.15 K, up to 10 MPa). The results indicate that sepiolite demonstrates superior adsorption capacity under all tested conditions, surpassing montmorillonite by over 12 times at 313.15 K for H2. Illite, chlorite, and kaolinite exhibit negligible H2 adsorption. Thermodynamic analysis reveals that H2 adsorption on clay minerals is a nonspontaneous and exothermic physisorption process. H2 loss due to adsorption hysteresis in montmorillonite and sepiolite is 42.19 and 3.56%, respectively. Sepiolite may exhibit more predictable and stable sorption properties under repeated pressure variations. The H2 adsorption capacity of montmorillonite and sepiolite is merely 0.4 and 4.5% of that of CO2, respectively. This study provides valuable insights for selecting clay minerals and cushion gases for efficient geological H2 storage and natural hydrogen exploration.

Application of Foam for Enhanced CO2 Geological Storage: A Mini-Review

Application of Foam for Enhanced CO₂ Geological Storage: A Mini-Review

Experimental and numerical analyses of creep-fatigue behavior in sandstone for energy storage applications

Porous sandstone formations are recognized as suitable hosts for the geological storage of clean energy sources such as hydrogen and compressed air. From a geomechanical perspective, the deformation mechanisms of the host rock must be understood under various loading and unloading conditions resulting from daily or hourly injection/production cycles. This study presents a combined experimental and numerical analysis of sandstone behavior under cyclic loading conditions. We present the results of several multi-level, multi-frequency cyclic loading experiments conducted on sandstone specimens. Three distinct deformation regimes are identified in these tests: 1) instantaneous elastic deformation; 2) transient and steady-state strain accumulation associated with creep; and 3) accelerated deformation and fatigue failure at high stress levels caused by the progressive development of micro-cracks. Furthermore, the experiments show that fatigue failure is accompanied by a rapid stiffness degradation within the specimens. Based on these observations, we propose a viscoelastic-damage model to characterize the creep-fatigue behavior in sandstone. The model combines the standard Burger's viscoelasticity with an energry-driven energy-driven damage model. The performance of the model is verified against results obtained from laboratory experiments. Finally, a parametric analysis is presented to assess the effects of the frequency and magnitude of the cyclic loads on the fatigue life of sandstone. These findings indicate that increasing the magnitude and frequency of cyclic stress can accelerate fatigue failure. These insights can be used to optimize design parameters to maintain the stability of sandstone rock masses in geological energy storage applications.

Analysis of dynamic characteristics and influencing factors of CO2 low-permeability coal reservoir sequestration

ABSTRACT Abandoned coal seams can be an important carrier for CO2 geological storage. Considering the gas seepage-diffusion and physical adsorption coupling characteristics in the process of CO2 adsorption and storage in coal and rock, a two-dimensional model of coupled flow-solidity for geological storage of CO2 in low-permeability reservoir with double voids was established by introducing the Zhang Hongbin model algorithm and adding the Klinkenberg effect and the compression effect of the rock skeleton in coal reservoirs in the controlling equation for rock deformation. The coupled flow-solid model was solved by using the PDE equation of COMSOL Multiphics program, and the simulation results difference between the new model and the traditional model in terms of sequestration dynamics were compared. The dynamic characteristic of reservoir gas pressure, formation stress, permeability and sequestration density in the process of CO2 geologic sequestration and injection were analyzed, and the influences of injection pressure and injection well diameter on the amount of CO2 sequestration were explored. The results show that the new model is more reasonable for calculating reservoir gas pressure and permeability compared with the Palmer-Mansoori model (PM model), and can simulate the free-state seepage movement of CO2 in the fracture system as well as its physical adsorption process compared with the single-heavy pore medium model. With continuous CO2 injection, the maximum sequestration density was raised to a limit value of about 1000 kg/m3 after 1 year. The date of reaching the limit of the sequestration volume was advanced by about 45 d when the positive pressure of the injected gas was increased from 10 kPa to 50 kPa. This model can reproduce the main parameters including, when affecting the effect, and realize the calculation of parameters such as CO2 density reaching the limit value, sealing limit day, sealing limit amount, which can provide a theoretical basis for further deep understanding of CO2 geological sealing law and scientific development of gas injection scheme.

Research on the Biogas Production Mechanism of Mudstone in the Qaidam Basin under Different CO2 Pressures.

Mudstone, a class of sedimentary rocks rich in organic matter, possesses considerable potential for biogas production. Mudstones possess a rich biological origin, which is conducive to refining the mechanisms and enrichment patterns of biogenic gas reservoirs. This has significant theoretical and practical implications for guiding the exploration and development of Quaternary mudstone gas reservoirs. Furthermore, the Qaidam Basin is an excellent place for the geological storage of CO2 due to its rich petroleum reservoir conditions. Experimental research on biogas production under diverse CO2 pressure-mudstone-microorganism-water interactions is conducted to determine the biogas production mechanism of mudstone under different CO2 pressures during sequestration circumstances. According to the results: (1) under supercritical carbon dioxide conditions, there is a slight initial increase in biogas production, followed by a gradual decrease. The periods and peaks of gas production vary among the different reaction groups. As carbon dioxide pressure increases, the gas production cycle lengthens significantly, while the gas yield declines. (2) Siderite and secondary carbonate minerals have increased in the mudstone's mineral fraction both before and after biogas production, while clay mineral groups have decreased. Specifically, there was a notable drop in chlorite and kaolinite. (3) Microorganism species in the system were analyzed, and the results showed that there was a gap in each microorganism's ability to adapt to its surroundings, and the diversity and quantity of bacteria declined with increasing pressure. After carbon dioxide was fluxed, there was a considerable shift in the pattern of biogas generation, which consequently had a major impact on the alterations in mineral fractions.

Research on microscale displacement characteristics of supercritical CO2 fracturing in shale oil reservoirs

AbstractThe great success of CO2 fracturing in shale oil reservoirs has not only increased the production capacity of shale oil, but also effectively carried out CO2 geological storage. In this paper, focusing on the microscale displacement characteristics of CO2 fracturing in shale oil reservoirs, first, the impact of oil saturation and gas invasion pressure on gas invasion is discussed. Then, the coupling control mode of oil saturation/pressure for various mechanisms of gas invasion is revealed. Results show that: (a) at lower displacement, the rock core has a lower initiation pressure and is fractured in a shorter period of time; (b) at higher displacement, the required fracturing time is longer and the fracturing pressure increases, but the fracturing effect is good and it is easy to form complex fracture networks; and (c) under higher pressure conditions, more complex fractures can be formed, which is beneficial for reservoir transformation and production improvement.

Numerical simulation of seasonal underground hydrogen storage: Role of the initial gas amount on the round-trip hydrogen recovery efficiency

Subterranean structures such as aquifers and depleted gas reservoirs (DGRs) offer a scalable, high-pressure, secure, cost-efficient, and ecologically friendly means of hydrogen (H2) storage. Underground H2 storage (UHS) has emerged as a potential solution to alleviate the imbalance between the fluctuating renewable energy generation and the demand for a constant energy supply. Quantifying the recovery efficiency is of paramount importance in the effort toward large-scale UHS. In this numerical simulation study, we employed a high-resolution grid for the discretization of a synthetic (but realistic) heterogeneous anticline intended as a H2 storage facility, and we assessed the H2 recovery efficiency, and the purity of produced gas associated with UHS in natural reservoirs involving different pre-existing gases and their quantities. All of these studies included an initial phase of cushion gas injection, followed by 4 cycles of H2 storage operations composed of injection-idle-withdrawal periods. The simulation results indicated that the H2 round-trip recovery efficiency RH increased (a) with an increasing number of storage cycles, routinely exceeding 90% and providing evidence of a self-enhancement or self-optimization H2 recovery mechanism and (b) with an increasing amount of pre-existing gas in the storage zone prior to the H2 injections — at the end of the 4-cycle test, the highest RH is associated with a DGR with a pre-existing gas consisting of residual CH4 and additional injected N2, and the lowest RH corresponds to an aquifer with no cushion gas. Conversely, the H2 mass fraction of the produced gas FHQ (a) increased with an increasing number of storage cycles, but (b) decreased rapidly with an increasing amount of pre-existing gas. The presence of a pre-existing gas inevitably leads to severe contamination of the produced H2, which never exceeds 40% in the produced gas, can be as low as 4% in early cycles, and cannot be used as a H2 fuel without gas separation. Aquifer storage without a cushion gas may exhibit the lowest H2 recovery (about 75% in the long run), but yields practically pure H2 that does not require further processing before use. A positive conclusion is that, under the conditions of this study, total H2 losses (including H2 escaping into the caprock, and inaccessible H2 dissolved in the aqueous phase of the formation or remaining in the gas storage zone) are limited and manageable, indicating the technical feasibility of geologic H2 storage.

Molecular insights into the formation of carbon dioxide hydrates on the external surface of sodium montmorillonite in the presence of various types of organic matters

To address the urgent challenge of global climate change due to the greenhouse effect resulting from increasing carbon dioxide (CO2) emissions, viable technologies for geological CO2 storage must be developed. Of such technologies, CO2 hydrates holds significant promise for CO2 storage in seabed sediments, which typically contain clay minerals and organic matter (OM). Thus, investigating the structure of clay mineral interfaces and their interactions with OM is crucial for understanding the nucleation and growth of CO2 hydrate in seabed sediments. In this study, molecular dynamics simulations were used to investigate CO2 hydrate formation on the external surface of sodium montmorillonite (Na-Mnt) in the presence of various types of OM. The results show that the Na-Mnt surface adsorbed certain numbers of sodium ions (Na+) and OM molecules. The hydration of Na + disrupted of the hydrogen bond structure of CO2 hydrates, while hydrogen bonds that formed between OM and H2O molecules hindered CO2 hydrate formation. Consequently, CO2 hydrates predominantly formed in the bulk-like solution away from the Na-Mnt. However, the electrostatic interaction between the carboxyl groups of OM and Na+ mitigated the inhibitory effect of Na+ on CO2 hydrate formation. Over all, these findings can serve as a fundamental theoretical basis for understanding the formation and occurrence characteristics of CO2 hydrates in seabed sediments with a rich Mnt content. Such understanding will help to advance the development of CO2 storage technologies utilizing CO2 hydrates in seabed sediments.

Stochastic control of geological carbon storage operations using geophysical monitoring and deep reinforcement learning

Geological carbon storage (GCS) is the process of injecting and storing carbon dioxide (CO2) in the subsurface to reduce greenhouse gas emissions. Safe and profitable GCS operations require effective decision-making in the presence of uncertain geological models, a process which can often be facilitated with geophysical monitoring. In this study, we examine how sequential decision-making algorithms can be combined with geophysical measurements for the optimal control of GCS operations. Specifically, we develop an artificial intelligence model using deep reinforcement learning (DRL) that takes geophysical time-lapse gravity and well pressure monitoring data as input and delivers an optimal CO2 injection policy. The objective of the problem at hand is to maximize the profit of a hypothetical GCS operation while mitigating the potential for induced seismicity, by training DRL agents using combined geostatistical, reservoir and geophysical simulation. Comparisons against two benchmarks – a constant injection strategy and an injection schedule optimized using a commercial reservoir simulator toolbox – show that the stochastic control of such operations from subsurface monitoring data using deep reinforcement learning is feasible. Evaluation results show that DRL agent behavior generates profits which are on average 1 to 8 percent higher than what is possible through a constant injection approach. Furthermore, we show that DRL can generate optimal injection policies applicable to the true (yet previously unseen) subsurface given carefully managed levels of uncertainty.

A national-scale high-resolution CCUS-shared pipeline layout for retrofitting multisectoral plants via onshore-offshore geological storage

Carbon capture utilization and storage (CCUS) is an indispensable process to mitigate climate change. However, a precise and feasible CCUS layout with realistic geospatial connectivity is essential to support the prospective deployment of multisectoral plants on a national scale. This study proposed an onshore-offshore CCUS source-sink matching model, distinguished by CO2 source-sink dataset enhancement, realistic pipeline network optimization, and onshore-offshore geospatial connectivity to accurately map China's high-resolution CCUS layout. The findings showed that China's multisectoral CCUS supply potential of coal-fired power, steel, cement, and coal chemicals was approximately 1.75, 0.77, 0.56, and 0.23 Gt/a CO2, respectively. A complete geospatial connectivity pattern was established by connecting 1186 multisectoral CO2 sources with 307 onshore and 22 offshore storage sites via the shared pipeline network of 80,700km, involving plant-level cost heterogeneity, industry competition, and CCUS cluster identification. This model can be applied to other countries or globally to enhance CCUS layout strategies.

Behaviors of hydrate cap formation via CO2-H2O collaborative injection:Applying to secure marine carbon storage

Leakage prevention of carbon dioxide (CO2) determines the safety of carbon marine geological storage. Hydrate caps have been proven to be one of the most effective structures for preventing CO2 leakage, which has attracted worldwide attention. However, the structure and formation behavior of hydrate caps during CO2 storage process are still unclear. In this study, a strategy of CO2-H2O co-injection was proposed to simulate the actual flow process and accelerate the hydrate cap formation rate. A series of CO2-H2O flow rates (0.25–10 mL/min) were employed. The results show that there will be four stages for the dynamic formation process of hydrate cap: fluid migration and diffusion, local hydrate formation, local area plugging, and hydrate cap formation. What's more, the water-gas flow ratio is inversely proportional to hydrate cap formation rate and positively proportional to the carbon storage efficiency. Meanwhile, the huge sealed capacity of hydrate cap was also proved in this work. The sequestration pressure of CO2 under hydrate cap exceeds 12 MPa, and the maximum carbon storage efficiency increases from 53.12% to 93.30%. Moreover, the macrostructure of hydrate cap consists of two layers with a certain hydrate saturation: the zero-permeability layer and the low-permeability layer. The zero-permeability layer determined the sealed capacity of hydrate cap. These findings may provide a theoretical foundation for the prevention of CO2 leakage in actual project of carbon marine geological storage.

Exploring the influences of salinity on CO2 plume migration and storage capacity in sloping formations: A numerical investigation

Accurate evaluation of CO2 plume migration, potential leakage, and storage capacity are the main challenges for CO2 geological storage (CGS). This study develops a suite of numerical models, focusing on the Shiqianfeng Formation of the Shenhua-Carbon Capture and Storage (CCS) demonstration project in the Ordos Basin, China, aiming to numerically evaluate the influence of combining salinity, dip angle, and faulting factors on CO2 plume migration, storage amount, conversion of gas and dissolved phase states. Simulation results show that lower salinity and larger dip angles result in earlier CO2 leakage. Increasing salinity from 0.00 to S in a 10° sloping formation causes later CO2 leakage (205–260 years). Lower salinity enhances CO2 plume migration, injection amount, and dissolved-phase CO2. As the salinity decreased from S to 0.00 in a 3° sloping formation over 120 years of CO2 migration, the dissolved CO2 plume migration increased by 9.1 %, the total CO2 amount increased by 70.0 %, and the proportion of dissolved CO2 increased by 13.07 %. Compared to formation dip angle, salinity has a more significant impact on the plume migration of dissolved CO2. However, CO2 storage safety decreases with increasing dip angle. The conversion proportion (1.88 %–9.75 %) of gas-phase to dissolved CO2 increased with an increasing dip angle and decreasing salinity for the first 100 years after injection ceased. Thus, we conclude that salinity, dip angle and faulting are important factors during CGS, and this study may provide a practical reference for further studies for evaluating CO2 storage potential.

A Statistical Analysis of Fluid Interface Fluctuations: Exploring the Role of Viscosity Ratio.

Understanding multiphase flow through porous media is integral to geologic carbon storage or hydrogen storage. The current modelling framework assumes each fluid present in the subsurface flows in its own continuously connected pathway. The restriction in flow caused by the presence of another fluid is modelled using relative permeability functions. However, dynamic fluid interfaces have been observed in experimental data, and these are not accounted for in relative permeability functions. In this work, we explore the occurrence of fluid fluctuations in the context of sizes, locations, and frequencies by altering the viscosity ratio for two-phase flow. We see that the fluctuations alter the connectivity of the fluid phases, which, in turn, influences the relative permeability of the fluid phases present.

Learning CO[formula omitted] plume migration in faulted reservoirs with Graph Neural Networks

Deep-learning-based surrogate models provide an efficient complement to numerical simulations for subsurface flow problems such as CO2 geological storage. Accurately capturing the impact of faults on CO2 plume migration remains a challenge for many existing deep learning surrogate models based on Convolutional Neural Networks (CNNs) or Neural Operators. We address this challenge with a graph-based neural model leveraging recent developments in the field of Graph Neural Networks (GNNs). Our model combines graph-based convolution Long-Short-Term-Memory (GConvLSTM) with a one-step GNN model, MeshGraphNet (MGN), to operate on complex unstructured meshes and limit temporal error accumulation. We demonstrate that our approach can accurately predict the temporal evolution of gas saturation and pore pressure in a synthetic reservoir with impermeable faults. Our results exhibit a better accuracy and a reduced temporal error accumulation compared to the standard MGN model. We also show the excellent generalizability of our algorithm to mesh configurations, boundary conditions, and heterogeneous permeability fields not included in the training set. This work highlights the potential of GNN-based methods to accurately and rapidly model subsurface flow with complex faults and fractures.

Volcanic weathered crust reservoir analog: Insights from fault-controlled fracture permeability in the trachytic rocks of the Pernambuco Basin, NE Brazil

Naturally fractured volcanic rocks represent a globally significant potential hydrocarbon reservoirs and can also be used for CO2 storage; however, the study of volcanic reservoirs in Brazil is limited. Although numerous volcanic reservoir types have been classified, relatively few studies are dedicated to the weathering of crust-like reservoirs, i.e., volcanic rocks undergoing subaerially alteration by weathering prior to deep burial. This study aims to characterize a volcanic weathered crust reservoir analog located in the coastal zone of the Pernambuco Basin, NE Brazil. We applied a multiscale approach motivated by the expressive potential of volcanic rocks as reservoirs in this marginal basin and considered their implications for CO2 geological storage projects. The deformational aspects observed in this analog have also been observed in other volcanic rocks that crop out in the coastal zone, thus, the data provided here can guide future characterization of both onshore and offshore reservoirs. We focused on an 80 m wide outcrop and employed geometric and topological analysis of two-dimensional fracture networks to investigate the influence of regional fault zone control on the fracture permeability tensors. The parameters of fracture systems were studied using terrestrial gravimetric data, orthophoto mosaic obtained by an unmanned aerial vehicle (UAV), petrography, and outcrop-based structural data. The investigated outcrop includes porphyritic trachytes with euhedral sanidine crystals and minor quartz phenocrysts, sourced from the Ipojuca Magmatic Suite. The residual Bouguer map indicates the influence of at least two regional rift fault zones, i.e., NW-SE (strike-slip) and NE-SW (normal) trending systems, in the studied rocks. These trachytic rocks exhibited a marked dissolution of sanidine phenocrysts and matrix, columnar disjunctions, and natural fractures, causing the porosity and permeability of the reservoir analog to increase. Geometric and topological analyses showed that the south-central sector of the outcrop exhibits heightened connectivity within the fracture network. Furthermore, the principal fracture permeability is controlled by the primary families of the fracture network and regional fault zones. Our results demonstrate that the fracture network observed in the volcanic reservoir analog was influenced by the post-rift tectonic reactivation of Cretaceous structures within the Pernambuco Basin. The secondary porosity resulting from weathering and subsequent dissolution of the primary constituents and fractures of the rocks studied demonstrates the potential for the exploration of these reservoirs as models for known occurrences of volcanic rocks in the onshore and offshore domains of the Pernambuco Basin.

Hydrogen adsorption kinetics in organic-Rich shale reservoir rocks for seasonal geological storage

The geo-storage of hydrogen (H2) is essential for advancing a robust and industrial-scale H2-based economy. The efficient H2 storage in a geological formation depends on the presence of a secure and impermeable caprock, such as a shale formation. However, the existing literature lacks information on the kinetics of H2 adsorption in actual shale formations with diverse organic contents and mineral compositions. Therefore, the kinetics of H2 adsorption in organic-rich shale samples from a Jordanian oil (JO) source rock formation are experimentally investigated herein at various temperatures (193, 273, 303, and 333 K) and two equilibrium pressures (15 and 45 bar) by using a volumetric method. The impact of mineral compositions and total organic content (TOC) on H2 adsorption is studied using two samples with distinct mineralogy and TOC values. Thermodynamic calculations are performed, and common adsorption models are used to analyze the experimental data. The results indicate that the H2 adsorption rate increases with pressure and decreases with temperature, being characterized by an initial rapid adsorption phase followed by a slower adsorption period as the uptake of H2 approaches equilibrium. More interestingly, the rate of H2 adsorption is higher in the sample with a high TOC and a richer composition of carbonate minerals. Both the applied adsorption isotherm models and adsorption kinetics models fit the experimental data remarkably well, thereby indicating their suitability for analyzing the kinetics of H2 adsorption in the JO shale. The unipore model matches the H2 kinetics data well, with R2 > 0.91. The H2 diffusion coefficient increases with pressure and temperature, where the H2 diffusion in shale accelerates with thermal motion intensity. This study provides fundamental insights into the adsorption kinetics of H2 and is expected to assist in implementing an industrial H2-based economy.