Geologic Carbon Sequestration Research Articles

A comprehensive review of efficient capacity estimation for large-scale CO2 geological storage

Geological carbon storage and sequestration (GCS), a key method within carbon capture and sequestration (CCS), is globally recognized as an effective strategy to reduce atmospheric carbon dioxide (CO2) levels and combat the greenhouse effect. However, discrepancies between projected and actual storage capacities, especially in large-scale CO2 storage, have raised concerns among stakeholders regarding potential overestimations. This paper reviews the definitions and methods used to estimate storage capacity, highlighting variations and providing a practical guide for predictions while suggesting directions for future research. We discuss numerous analytical and numerical models that account for dynamic constraints such as safety considerations, trapping mechanisms, and reservoir performance, primarily focusing on local scales. These models enhance the accuracy of capacity estimations over conventional static models by quantifying CO2 storage capacity both spatially and temporally. Additionally, this review underscores the need for sophisticated evaluations of large-scale storage. We introduce two pivotal tools designed for basin-scale capacity estimation and discuss the challenges associated with expanding dynamic capacity assessments to larger scales. In conclusion, the paper explores the burgeoning use of machine learning-based models, advocating for future research efforts to leverage machine learning in developing integrated tools that offer more comprehensive and precise capacity estimations for GCS.

Insight into evolution of invasive patterns on fingering phenomenon during immiscible two-phase flow through pore structure

Understanding fingering, as a challenge to stable displacement during the immiscible flow, has become a crucial phenomenon for geological carbon sequestration, enhanced oil recovery, and groundwater protection. Typically governed by gravity, viscous and capillary forces, these factors lead invasive fluids to occupy pore space irregularly and incompletely. Previous studies have demonstrated capillary numbers, describing the viscous and capillary forces, to quantificationally induce evolution of invasion patterns. While the evolution mechanisms of invasive patterns have not been deeply elucidated under the constant capillary number and three variable parameters including velocity, viscosity, and interfacial tension. Our research employs two horizontal visualization systems and a two-phase laminar flow simulation to investigate the tendency of invasive pattern transition by various parameters at the pore scale. We showed that increasing invasive viscosity or reducing interfacial tension in a homogeneous pore space significantly enhanced sweep efficiency, under constant capillary number. Additionally, in the fingering crossover pattern, the region near the inlet was prone to capillary fingering with multi-directional invasion, while the viscous fingering with unidirectional invasion was more susceptible occurred in the region near the outlet. Furthermore, increasing invasive viscosity or decreasing invasive velocity and interfacial tension promoted the extension of viscous fingering from the outlet to the inlet, presenting that the subsequent invasive fluid flows toward the outlet. In the case of invasive trunk along a unidirectional path, the invasive flow increased exponentially closer to the outlet, resulting in a significant decrease in the width of the invasive interface. Our work holds promising applications for optimizing invasive patterns in heterogeneous porous media.

Water thin films on kaolinite gibbsite and edge surfaces and their effects on surface wettability in relation to geological carbon sequestration

Geological carbon sequestration (GCS) is a promising method to alleviate CO2 emission, while CO2 structural trapping is one of main GCS mechanisms, in which the storage capacity is strongly dependent on CO2-water–rock contact angle. Although CO2-water-kaolite contact angle on basal surfaces has been studied, the knowledge about kaolinite edge surface wettability remains unknown. In this work, we use molecular dynamics (MD) simulations to study CO2-water-kaolinite contact angle on kaolinite gibbsite and edge surfaces under a typical GCS condition (330 K and 200 bar). The common belief is that surface wettability in presence of water is determined by surface hydroxyl (–OH) group density. While the surface –OH group density of kaolinite edge surface is much lower than that of gibbsite surface, both gibbsite and edge surfaces are strongly water-wet. Edge surface is better hydrated than gibbsite surface as both silanol and aluminol groups can form hydrogen bonding with water molecules thanks to large effective water accessible volume around them, while pocket water can further anchor water film. Therefore, the atomic-level surface characteristics dictate interfacial water structures which determine CO2-water-kaolinite contact angle. Our study provides important insights into the effect of surface heterogeneity on interfacial water structures, and kaolinite gibbsite and edge surface wettability which is crucial to the optimization of GCS processes.

An encoder-decoder ConvLSTM surrogate model for simulating geological CO2 sequestration with dynamic well controls

In Geological Carbon Sequestration (GCS), effectively managing the project requires predicting state variables such as pressure and saturation. However, numerical simulation of multiphase flow in subsurface porous media involves solving large linear algebra systems, resulting in a substantial computational burden. This can make it impractical for real-time history matching or optimization. Meanwhile, deep learning-based surrogate models are emerging as fast and accurate approximators. This study delves into the application of the Encoder-Decoder Convolutional Long Short-Term Memory (ED-ConvLSTM) neural network for predicting the complex evolution of state variables under dynamic CO2 injection schemes. Inception blocks enhanced with light-weighted attention modules are introduced in the encoder to extract high-dimensional input features. ConvLSTM is employed to propagate spatial temporal information in the low-dimensional latent space. Further, progressive upsampling blocks are used to reconstruct the latent features for the desired output. Instead of taking discrete time steps as an input feature, the proposed network captures the dynamic dependencies with the inherent ConvLSTM cell. The network has access to data at only portion of the initial time steps during training stage, while it is used to predict the state variables at unseen time steps during testing stage. Results show that the network can produce excellent predictions for both pressure and saturation, even at unseen future time steps. The remarkable generalizability to different geological permeability fields is also evaluated. ED-ConvLSTM outperforms the standard U-Net by far, especially when predicting beyond the training time period. These numerical experiments demonstrate the advantages of ED-ConvLSTM in terms of prediction accuracy, extrapolability and generalizability. This study highlights the importance of incorporating recurrent connections into the deep neural networks for simulating time-dependent multiphase flow problems. The proposed methodology has great potential in GCS surrogate modeling and offers a possible approach for real-time optimization of CO2 injection.

Mechanical integrity of tubular elements based on strength and fracture criteria during transient CO2 injection

Geological carbon sequestration (GCS) is an essential technology for reducing carbon emissions. Wellbore integrity is crucial to ensure the safety of GCS. During low-temperature carbon dioxide (CO2) injection, the wellbore temperature decreases, causing the tubing and casing to contract, resulting in considerable axial tensile stresses, and making mechanical failure likely. This paper establishes a transient flow model for CO2 injection to predict the temperature and pressure distribution in the wellbore. Then, the strength safety factor of the tubing and casing is calculated using the material strength criteria. Fracture mechanics theory is employed to analyze the risk of crack propagation in defective tubing or casing during CO2 injection. The study indicates that the wellbore temperature near the wellhead is lower as CO2 is injected. Under typical injection conditions, the tubing and casing have high strength safety factors but small crack propagation factors. The stress intensity factor of cracks on the tubing and casing's outer surface is more significant than inner surface defects, posing a higher risk of crack propagation. When the tubing or casing exits a penetrating crack, its propagation safety factor is less than 1, necessitating the avoidance of through-wall cracks. The results guide maintaining wellbore integrity in carbon dioxide geological sequestration engineering.

Investigation of CO2-EOR and storage mechanism in Injection-Production coupling technology considering reservoir heterogeneity

Heterogeneous reservoirs offer greater potential for increased oil production and carbon storage capacity when using CO2 injection-production coupling technology in a broader range of geological formations. However, the impact of heterogeneity on the mechanisms and effectiveness of CO2 utilization and storage remains unclear. This study comprehensively investigates the mechanisms of enhanced oil recovery and the sequestration potential of CO2 injection-production coupling technology in heterogeneous reservoirs using both microscopic visualization experiments and macroscopic core experiments. The results reveal that during continuous gas flooding, CO2 forms rapid flow channels, leading to the formation of oil films and columnar residual oil in high-permeability zones, while small pores remain unaffected. Meanwhile, under high-speed injection conditions, the overall microscopic recovery rate increases by 13.8%. However, a higher proportion of porous residual oil is retained in low-permeability zones. During asynchronous injection-production cycles, the microscopic recovery rate remains above 86%, indicating a more thorough utilization of porous residual oil, which is predominantly present in membranous and angular corner configurations. The mechanisms of enhanced oil recovery include the increase in energy, dissolution expansion, and displacement-transport mechanisms. In asynchronous injection-production mode, macroscopic recovery rates are all above 80%. Additionally, with an increase in permeability contrast, the CO2 utilization efficiency rises from 5.9% to 8.6%, demonstrating the high potential of injection-production coupling technology for enhanced oil recovery and geological carbon sequestration in heterogeneous reservoirs. This study provides theoretical support for CO2 injection development and geological sequestration in heterogeneous reservoirs.

Combining Steam and Flue Gas as a Strategy to Support Energy Efficiency: A Comprehensive Review of the Associated Mechanisms.

Conventional steam injection projects have long been an iconic process in the development of heavy oil reserves; nevertheless, they face significant challenges in terms of energy efficiency, environmental compliance, and economic viability. Factors such as oil price fluctuations, the imperative for an energy transition, and the push to reduce carbon footprints are hindering new or ongoing implementations of traditional steam injection technologies. In response to these challenges, hybrid methods, such as the combination of steam and flue gas, are emerging as an opportunity to optimize thermal processes to improve oil recovery, energy efficiency, and environmental sustainability and extend reservoir productivity life. Steam injection enhances oil recovery by reducing the viscosity of crude oil, improving oil mobility and facilitating its extraction. The utilization of flue gas in steam injection processes has a significant impact on oil recovery and energy efficiency, leveraging industrial byproducts. This not only lowers operating costs but also reduces environmental emissions, aligned with energy transition trends. Incorporating the flue gas into a steam-based process in heavy oil reservoirs has emerged as a promising thermally enhanced oil recovery strategy. This work presents a comprehensive review based on experimental, numerical, and field studies of hybrid steam and flue gas technology as an EOR process. The main recovery mechanisms associated with the process are analyzed. In addition, the laboratory equipment required for experimental evaluations is presented, and reservoir modeling, kinetic and compositional effects on reservoir fluids, and the reduction in heat losses in the steam injection process are discussed. Furthermore, field implementations are reviewed to evaluate lessons learned and experiences on an operative scale. The combination of steam and flue gas represents an opportunity for carbon utilization and geological carbon sequestration. This dual functionality underscores its potential to enhance oil recovery and address carbon-related environmental concerns.

Simulation of CO2 dissolution reactions in saline aquifers using lattice Boltzmann method

CO2 dissolution reactions in saline aquifers during geologic carbon sequestration (GCS) involve multiple physicochemical processes and pose a challenge for both experimental and numerical techniques to capture reactive transport features and complex porous structures. Benefited from advanced models in the lattice Boltzmann (LB) community, namely, multiphase flow LB model and multicomponent transport LB model with chemical reactions, dynamics of CO2-water interfaces, concentration evolution of ions, and heterogeneous and homogeneous reactions could be readily captured by the proposed LB model to characterize CO2 dissolution reactions applicable to far-field applications. This LB model can not only emphasize CO2 dissolution processes at the scale of a few pores but also elaborate on the corresponding controlling mechanisms in porous media during GCS in saline aquifers. LB simulations herein indicate that both diffusion coefficient and reactive interfacial length may change the total concentration gradient at the CO2-water interface to further affect CO2 dissolution reactions. It is also confirmed that CO2 dissolution is a non-equilibrium process, which could not be neglected in reservoir-scale simulations. The effect of reactive interfacial length on CO2 dissolution is negligible due to a narrower range of contact angles in saline aquifers. Influenced by the structural complexity of porous media, the dissolution of CO2 clusters shows a strong heterogeneous characteristic evaluated by the pore size distribution. The evolution of pH in homogeneous reactions is estimated via mass action equations. Besides, the effects of partial pressure, formation temperature, and salinity, as three key factors in the practical application, are thoroughly probed. The high pressure is conducive for sequestration because of its greater sequestration efficiency, but the temperature has both positive and negative impacts on CO2 dissolution trapping and should be carefully evaluated in a certain saline aquifer before the operation. High ion strength would decrease the efficiency of dissolution trapping to some extent.

Deep learning-assisted Bayesian framework for real-time CO2 leakage locating at geologic sequestration sites

Accurate and efficient localization of CO2 leakage if occurred in subsurface formations, is of significant importance in achieving secure geological carbon sequestration (GCS) projects. However, this task is inherently challenging due to the considerable uncertainties in the subsurface. In this work, we develop a novel deep learning-assisted Bayesian framework for identifying potential CO2 leakage sites based on the reservoir pressure transient behavior measured at the wellbores of injection or observation wells. The method consists of two essential steps: 1) Deep learning surrogate: This step aims to effectively replace the intensive high-fidelity simulation with an efficient deep learning surrogate. 2) Bayesian inversion: In this step, the posterior distributions of potential CO2 leakage locations are inverted, in which the surrogate serves as the forward model. The above two processes are automated using Bayesian optimization instead of a labor-intensive trial-and-error approach. The proposed framework is verified using a 3D geological model simulating CO2 sequestration into a brine-filled reservoir. The results demonstrate the Bayesian-optimized surrogate could successfully capture the underlying process of subsurface CO2-brine flow. The Bayesian inversion algorithm enables localizing CO2 leakage with high accuracy. To our knowledge, the proposed Bayesian framework is implemented for the first time to locate multiple leakage sites at the field scale. The proposed workflow provides an accurate and efficient approach to detecting possible CO2 leakage locations in a real-time manner and has promising potential for field-scale GCS applications.

Machine Learning-based 4-D Seismic Data Integration and Characterization of Channelized Anticline Aquifer for Geological Carbon Sequestration

Machine Learning-based 4-D Seismic Data Integration and Characterization of Channelized Anticline Aquifer for Geological Carbon Sequestration

Engineering Meter-scale Porous Media Flow Experiments for Quantitative Studies of Geological Carbon Sequestration

This technical note describes the FluidFlower concept, a new laboratory infrastructure for geological carbon storage research. The highly controlled and adjustable system produces a strikingly visual physical ground truth of studied processes for model validation, comparison and forecasting, including detailed physical studies of the behavior and storage mechanisms of carbon dioxide and its derivative forms in relevant geological settings for subsurface carbon storage. The design, instrumentation, structural aspects and methodology are described. Furthermore, we share engineering insights into construction, operation, fluid considerations and fluid resetting in the porous media. The new infrastructure enables researchers to study variability between repeated CO2 injections, making the FluidFlower concept a suitable tool for sensitivity studies on a range of determining carbon storage parameters in varying geological formations.

Integrated containment risks assessment for subsurface CO2 storage: Overburden analysis and top seal integrity study, offshore Norway

This study summarizes the OASIS (Overburden Analysis and Seal Integrity Study for CO2 Sequestration in the North Sea) project that focuses on assessing the containment risks associated with the geological carbon sequestration (CCS) of the Northern Lights project. CCS is viewed as one of the most effective solutions for reducing carbon emissions, as it captures carbon dioxide from point sources and permanently stores it in suitable geological formations. However, injecting CO2 into the subsurface may have mechanical consequences, including fault reactivation, top seal fracturing, surface heave, etc. This study proposes an interdisciplinary workflow to characterize the caprock, faults, and overburden associated with CCS projects in the Horda Platform area, to improve injection-induced containment risk assessment. Our findings show that the proposed workflows and tools effectively characterize stress-related mechanical hazards. However, due to the complex nature of rocks, it is challenging to evaluate the top seal integrity using a single method. Therefore, the proposed interdisciplinary approach is more effective for any fluid injection site's characterization, given the complex nature of the subsurface and its behavior under injection-induced stress changes. This research paper adds knowledge about the top seal integrity assessment and the reliability of injected CO2, making CCS projects more reliable and safer. Although this study focuses on the northern North Sea, the proposed methods are equally applicable globally to characterize subsurface CO2 storage sites. Apart from CCS projects, these research results can benefit other subsurface injection projects, such as water injection for reservoir management, wastewater injection for disposal, hydrogen storage, and hydraulic fracturing for unconventional hydrocarbon resources.

On the resilience of bio-cemented silica sands in chemically reactive environment

Exposure of geomaterials to an acidic environment is frequently encountered in modern-day geo-energy and geo-environmental engineering activities, in e.g. incorporation of chemical stimulation for unconventional shale gas exploitation, enhanced geothermal systems, geological carbon sequestration, and the long-term regional stability in carbonate-rich coastal areas. The Multiphysics-involved process for each application is complex and an optimised control calls for a better understanding on the coupling mechanism of the chemical, hydraulic and mechanical fields. This laboratory-based study aims to provide a quantitative calibration and derivation of the key coupling parameters accommodating our recently proposed framework of reactive chemo-mechanics, using a bio-cemented rock-like material as a representative for dissolvable rocks. The advantage of bio-cemented specimens (here by microbially induced carbonate precipitation) over natural rocks lies in their more uniform grain-bond structure and laboratory tunable calcite content. An experimental setup is introduced for investigating the role of calcite content on the mechanical and hydraulic properties of bio-cemented silica sands, followed by uniaxial tests on the bio-cemented specimens immersed in acidic environment to allow a reactive chemo-mechanical setting. Our results show that bio-cemented samples appear to be more “resilient” to an acidified aqueous environment in terms of less strength degradation compared to natural carbonate-rich rocks. Ductile failure mode is observed in the bio-cemented specimens within a certain range of the calcium carbonate content and a brittle-to-ductile transition in the failure mode occurs when the calcite content in the specimen decreases. With the calibrated model and the derived coupling parameters, we further illustrate an example of numerical prediction on the mechanical response of bio-cemented specimens under varying acidic environments and loading rates.

Impact of wettability on capillary phase trapping using pore-network modeling

The impact of rock wettability on phase mobility and capillary trapping is significant in the valuation of geologic carbon sequestration scenarios. Wetting conditions of CO2/brine/rock systems can vary from site to site and over time due to changes in temperature, pressure, salinity, mineral composition and surface roughness. Therefore, effective predictability of CO2 mobility and trapping in underground formations requires a thorough exploration of the relationship between wetting conditions and phase saturation over a wide range of contact angles. In this paper, we use pore-network modeling to investigate the effect of wettability on phase mobility and capillary trapping. We simulate different wetting and nonwetting conditions during secondary flooding cycles where the initial phase saturations are varied significantly. Characteristic initial-residual (IR) saturation curves and the locus of residual phase connectivity and saturation are determined for each wettability condition.Simulations show that when the receding phase is the wetting phase, there is reduced trapping of that phase owing to piston-like advance by the nonwetting phase and sustained layer flow of the wetting phase. Such flow regimes cause nonlinearity in the characteristic initial-residual (IR) saturation curve, which is not captured by traditional trapping models. A proposed extended Land-based model matches the IR trends for all wettabilities. Simulations also show that the loci of residual phase saturation and phase connectivity are a strong function of wettability. When the receding phase is strongly nonwetting, the locus remains nearly constant in phase connectivity, while at increasingly wetting conditions, the locus forms a closed-loop in the saturation-connectivity space, where the endpoint of the locus is constrained by pore topology as residual saturations approach low values.

Effects of roughness on density-driven convection of dissolved CO2 in discrete fracture-matrix system

Dissolution trapping is a permanent and safe mechanism for geological carbon sequestration. An increase in density caused by the dissolution of CO2 into brine can trigger a density-driven convection process. In this study, the effect of fracture roughness on the density-driven convection process in heterogeneous saline aquifers is numerically analyzed by using a three-dimensional rough fracture-matrix model. The results show that the variation of the fracture aperture, a microscale heterogeneity phenomenon, can result in the change of the macroscopic flow characteristics. The rough fracture surface intensifies the convection inside the fracture and makes the migration path of the solute more tortuous. The spatial variability of the aperture generates the merging of convective fingers and suppresses the development of weak convective fingers, thus further enhancing the longitudinal extent of convective mixing. It is indicated that neglecting roughness during the flux growth stage can lead to an underestimation of dissolved fluxes by about 20%. The consideration of fracture roughness variation can contribute to the better understanding and prediction of the dynamics of dissolved CO2 in real reservoirs.

Emergence of Unstable Focused Flow Induced by Variable‐Density Flows in Vertical Fractures

AbstractFluids with different densities often coexist in subsurface fractures and lead to variable‐density flows that control subsurface processes such as seawater intrusion, contaminant transport, and geologic carbon sequestration. In nature, fractures have dip angles relative to gravity, and density effects are maximized in vertical fractures. However, most studies on flow and transport through fractures are often limited to horizontal fractures. Here, we study the mixing and transport of variable‐density fluids in vertical fractures by combining three‐dimensional (3D) pore‐scale numerical simulations and visual laboratory experiments. Two miscible fluids with different densities are injected through two inlets at the bottom of a fracture and exit from an outlet at the top of the fracture. Laboratory experiments show the emergence of an unstable focused flow path, which we term a “runlet.” We successfully reproduce the unstable runlet using 3D numerical simulations and elucidate the underlying mechanisms triggering the runlet. Dimensionless number analysis shows that the runlet instability arises due to the Rayleigh‐Taylor instability (RTI), and flow topology analysis is applied to identify 3D vortices that are caused by the RTI. Even under laminar flow regimes, fluid inertia is shown to control the runlet instability by affecting the size and movement of vortices. Finally, we confirm the emergence of a runlet in rough‐walled fractures. Since a runlet dramatically affects fluid distribution, residence time, and mixing, the findings in this study have direct implications for the management of groundwater resources and subsurface applications.

Distribution of CO2-CH4 in a nanoslit medium and the efficiency of displacement of CH4 by CO2

The replacement of CH4 with CO2 in reservoirs is crucial for natural gas exploitation and sequestration of CO2. Therefore, the states and distribution patterns of coexisting CO2 and CH4 and the dynamic patterns of CH4 displacement by CO2 in mineral slits must be understood. Here, we simulate the molecular dynamics and displacement efficiency of CH4 in gypsum, quartz, and illite mineral slit models. The results demonstrate that gas density is not uniform throughout the slits and prove that gypsum and quartz have a greater adsorption capacity for CO2 than for CH4 and illite has a greater adsorption capacity for CH4. We find that (1) the application of the same force to different mineral slits leads to dissimilar CH4 displacement efficiencies, whereas an increase in the applied force in the same mineral slit is positively correlated with the CH4 displacement efficiency; (2) the main factor affecting CH4 displacement efficiency is CO2 adsorption; (3) the greater the adsorption capacity of mineral slits for CO2 (such as for gypsum), the more difficult it is to displace the CH4 in the slit despite large applied force; and (4) CH4 displacement efficiencies of illite, quartz, and gypsum decrease under the same conditions. These results provide a reference for theoretical research and industrial applications related to geologic carbon sequestration.

High-resolution geoelectrical characterization and monitoring of natural fluids emission systems to understand possible gas leakages from geological carbon storage reservoirs

Gas leakage from deep geologic storage formations to the Earth’s surface is one of the main hazards in geological carbon sequestration and storage. Permeable sediment covers together with natural pathways, such as faults and/or fracture systems, are the main factors controlling surface leakages. Therefore, the characterization of natural systems, where large amounts of natural gases are released, can be helpful for understanding the effects of potential gas leaks from carbon dioxide storage systems. In this framework, we propose a combined use of high-resolution geoelectrical investigations (i.e. resistivity tomography and self-potential surveys) for reconstructing shallow buried fracture networks in the caprock and detecting preferential gas migration pathways before it enters the atmosphere. Such methodologies appear to be among the most suitable for the research purposes because of the strong dependence of the electrical properties of water-bearing permeable rock, or unconsolidated materials, on many factors relevant to CO2 storage (i.e. porosity, fracturing, water saturation, etc.). The effectiveness of the suggested geoelectrical approach is tested in an area of natural gas degassing (mainly CH4) located in the active fault zone of the Bolle della Malvizza (Southern Apennines, Italy), which could represent a natural analogue of gas storage sites due to the significant thicknesses (hundreds of meters) of impermeable rock (caprock) that is generally required to prevent carbon dioxide stored at depth from rising to the surface. The obtained 3D geophysical model, validated by the good correlation with geochemical data acquired in the study area and the available geological information, provided a structural and physical characterization of the investigated subsurface volume. Moreover, the time variations of the observed geophysical parameters allowed the identification of possible migration pathways of fluids to the surface.

Multi-Scale Seismic Measurements for Site Characterization and CO2 Monitoring in an Enhanced Oil Recovery/Carbon Capture, Utilization, and Sequestration Project, Farnsworth Field, Texas

To address the challenges of climate change, significantly more geologic carbon sequestration projects are beginning. The characterization of the subsurface and the migration of the plume of supercritical carbon dioxide are two elements of carbon sequestration that can be addressed through the use of the available seismic methods in the oil and gas industry. In an enhanced oil recovery site in Farnsworth, TX, we employed three separate seismic techniques. The three-dimensional (3D) surface seismic survey required significant planning, design, and processing, but produces both a better understanding of the subsurface structure and a three-dimensional velocity model, which is essential for the second technique, a timelapse vertical seismic profile, and the third technique, cross-well seismic tomography. The timelapse 3D Vertical Seismic Profile (3D VSP) revealed both significant changes in the reservoir between the second and third surveys and geo-bodies that may represent the extent of the underground carbon dioxide. The asymmetry of the primary geo-body may indicate the preferential migration of the carbon dioxide. The third technique, cross-well seismic tomography, suggested a strong correlation between the well logs and the tomographic velocities, but did not observe changes in the injection interval.

Subcritical CO2 adsorption on geomaterials of coal-bearing strata in the context of geological carbon sequestration

This paper explores the adsorption behaviour of geomaterials in the framework of CO2 sequestration in shallow level coal seams. Manometric adsorption experiments were carried out on two anthracite coal samples, two rock samples from East Irish Sea, MX80-bentonite, Speswhite kaolinite, dry, wet and biofilm-laden (Bascillus mojavensis-laden) sand at subcritical pressure range (up to 6.4 MPa) of isothermal condition at 298.15 K. The experiments were aimed to investigate the influence of the biogeological conditions of coal and caprock constitutions on CO2 adsorption. At lower pressures, the moisture had an influence on the CO2 adsorption on coal resulted in reduced adsorption capacity. At elevated pressures, the volume expulsion behaviour and coal-water interaction had an influence on the adsorption capacities of moist coal sample and resulted in comparable adsorption capacities to dry sample. The disparity in the adsorption capacities between the wet powdered and wet intact core samples showed that the results obtained with powder samples may not reflect the field conditions. Wet conditions and Bascillus mojavensis bacteria influenced the adsorption capacity of sand and showed CO2 chemisorption capacity. The desorption isotherm pattern of wet and biofilm sand showed that the CO2 was continuously adsorbed independent of the gas phase pressure. Among the clay minerals, bentonite had greater affinity towards CO2. Despite the fact that the adsorption capacity of the cap rock is smaller than that of the coal samples, the experimental investigation with constituents of the cap rock provides insights into the effect of biogeological conditions of coal and rock sample constituents on CO2 storage in coal seams.