Reactive transport modeling for CO 2 geological sequestration

Subsurface Property Rights: Implications for Geologic CO2 Sequestration

Impacts of elevated dissolved CO2 on a shallow groundwater system: Reactive transport modeling of a controlled-release field test

Effect of oxygen co-injected with carbon dioxide on Gothic shale caprock–CO2–brine interaction during geologic carbon sequestration

Review of Carbon dioxide utilization and sequestration in depleted oil reservoirs

<p>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 or natural and artificial pathways, such as faults and well structures, are the main factors controlling surface leakages. Therefore, the characterization of natural systems, where large amounts of CO<sub>2</sub> are released, can be helpful for understanding the effects of potential gas leaks from storage carbon systems. In this framework, we propose a combined use of geoelectrical investigations (i.e., resistivity tomography and self-potential surveys) for characterizing natural CO<sub>2</sub> leakage areas, as well as gas storage sites. Such methodologies appear to be among the most suitable for revealing spatial distributions of carbon dioxide and monitoring subsurface fluid migration processes, because of the strong dependence of the electrical properties of water-bearing permeable rock, or unconsolidated materials, on many factors relevant to CO<sub>2</sub> storage (i.e., porosity, fracturing, water saturation, etc.). Indeed, the electric resistivity of porous water-bearing sediments decreases significantly when CO<sub>2</sub> dissolves in pore-water, in contrast to the effect in the gas phase and supercritical CO<sub>2</sub>, while the anomalous concentrations of natural electric charge are directly related to carbon dioxide migration along porous and fractured rock systems. The effectiveness of the suggested multi-methodological geoelectrical approach is tested in some areas of natural CO<sub>2</sub> degassing located in the Southern Apennines (Italy), which could represent natural analogues of gas storage sites. Specifically, electrical resistivity and self-potential surveys are targeted at reconstructing shallow buried fracture networks in the cap-rock and detecting preferential CO<sub>2</sub> migration pathways. Our findings are promising for imaging the CO<sub>2</sub> plume within a carbon storage reservoir and for identifying possible CO<sub>2</sub> leakages through the cap-rock formation, suggesting that the proposed approach can be very helpful also for the monitoring of carbon sequestration systems.  </p>

Carbon dioxide capture and sequestration (CCS) in deep geological formations has recently emerged as an important option for reducing greenhouse gas (GHG) emissions, and due to the complexity of the issue, CCS has turned into a multiple‐discipline research area. Environmental isotopes have been used in various CCS projects worldwide for evaluating trapping mechanisms, selecting storage sites, and monitoring for storage safety. Environmental isotopes are found useful in the investigation of many CCS issues and are particularly effective in identifying phase states (free, dissolved, and mineral state), and in quantifying structural, solubility, and mineral trapping forms of CO2. We used published laboratory results to successfully verify different methods for quantifying structural trapping mechanisms. Our results show that, in short time scales, saturation of the formation with free CO2‐phase can be obtained from oxygen isotope measurements on CO2 and/or reservoir brine, and carbon isotope of dissolved inorganic carbon can be used to trace dissolution in brine. Carbon isotopes and other parameters, such as CO2/3He ratio, can also be used to confirm the mineral trapping mechanism in natural gas fields. Environmental isotopes can also be used to distinguish mineralogical composition of formations, and to identify hydrodynamic conditions for site selection in addition to monitor potential CO2 leakage. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd

Numerical assessment of CO2 geological sequestration in sloping and layered heterogeneous formations: A case study from Taiwan

Geological carbon sequestration (GCS) involves injecting CO 2 into subsurface geological formations for permanent storage. Numerical simulations could guide decisions in GCS projects by predicting CO 2 migration pathways and the pressure distribution in storage formation. However, these simulations are often computationally expensive due to highly coupled physics and large spatial-temporal simulation domains. Surrogate modelling with data-driven machine learning has become a promising alternative to accelerate physics-based simulations. Among these, the Fourier neural operator (FNO) has been applied to three-dimensional synthetic subsurface models. Despite its good accuracy in simulating CO 2 plume migration, it requires large computational resources in training and also lacks generalizability. Here, to further improve performance, we have developed a nested Fourier-DeepONet by combining the expressiveness of the FNO with the modularity of a deep operator network (DeepONet). This new framework is twice as efficient as a nested FNO for training and has at least 80% lower GPU memory requirement due to its flexibility to treat temporal coordinates separately. These performance improvements are achieved without compromising prediction accuracy. In addition, the generalization and extrapolation ability of nested Fourier-DeepONet beyond the training range has been thoroughly evaluated. Nested Fourier-DeepONet outperformed the nested FNO for extrapolation in time with more than 50% reduced error. It also exhibited good extrapolation accuracy beyond the training range in terms of reservoir properties, number of wells, and injection rate.

This report presents data on the 140 existing and 74 planned ethanol production facilities and their proximity to candidate deep geologic storage formations. Half of the existing ethanol plants and 64% of the planned units sit directly atop a candidate geologic storage reservoir. While 70% of the existing and 97% of the planned units are within 100 miles of at least one candidate deep geologic storage reservoir. As a percent of the total CO2 emissions from these facilities, 92% of the exiting units CO2 and 97% of the planned units CO2 emissions are accounted for by facilities that are within 100 miles of at least one potential CO2 storage reservoir.

Combined geological, hydrogeological, and geochemical controls on the arsenic concentration of contaminated aquifers in SE Asia were explored by two‐dimensional (2‐D) reactive transport modeling of data sets from Bangladesh, Cambodia, and Vietnam. For each site, the field data are summarized and used to create a conceptual 2‐D reactive transport model that elucidates characteristic features influencing the groundwater arsenic concentration. Comparison of models for Bangladesh and Vietnam indicates that fine‐grained layers overlying young sandy aquifers generate shallow high arsenic groundwater because low vertical groundwater velocities allow sufficient time for kinetic As release from the sediment. The low vertical groundwater velocity below major river channels, predicted by the model, also creates long groundwater residence times, leading to high arsenic groundwater. Young aquifer sediments release more arsenic than older sediments, and alternating young and older sediments create complex patterns of high and low arsenic groundwater. Over time, floodplain basins will subside, and river channels migrate, causing sedimentation and erosion on the floodplain while creating local environments with evolving hydrogeology and groundwater geochemistry. We have developed a three‐step model for the evolution of the Red River floodplain with sedimentation and shifting channels over the last 6000 years. The results show comparable timescales between the dynamics of arsenic release and of river migration, causing complex groundwater As distributions, comprising geochemical palinopsia of long vanished rivers.

Fractures and defects in wellbore cement can lead to increased possibilities of CO2 leakage from abandoned wells during geological carbon sequestration. To investigate the physicochemical response of defective wellbore cement to CO2‐rich brine, we carried out a reactive flow‐through experiment using an artificially fractured cement sample at a length of 224.8 mm. A brine solution with dissolved CO2 at a pH of approximately 3.9 was injected through the sample at a constant rate of 0.0083 cm3/s. Surface optical profilometry analysis and 3‐D X‐ray microtomography imaging confirmed fracture closure and self‐healing behavior consistent with the measured permeability decrease. Visual inspection of the reacted fracture surface showed the development of reactive patterns mapping the flow velocity field inside the fracture, as well as restricted flow toward the sample outlet. The postexperiment permeability of the core sample was measured at half of its initial permeability. A reactive transport model was developed with parameters derived from the experiment to further examine property evolution of fractured cement under dynamic flow of CO2‐rich brine. Sensitivity analysis showed that residence time and the size of initial fracture aperture are the key factors controlling the tendency to self‐healing or fracture opening behavior and therefore determine the long‐term integrity of the wellbore cement. Longer residence time and small apertures promote mineral precipitation, fracture closure, and therefore flow restriction. This work also suggests a narrow threshold separating the fracture opening and self‐sealing behavior.

Multicomponent reactive transport of carbon dioxide in fluvial heterogeneous aquifers

As the global economy moves toward net-zero carbon emissions, large-scale energy storage becomes essential to tackle the seasonal nature of renewable sources. Underground hydrogen storage (UHS) offers a feasible solution by allowing surplus renewable energy to be transformed into hydrogen and stored in deep geological formations such as aquifers, salt caverns, or depleted reservoirs, making it available for use on demand. This study thoroughly evaluates UHS concepts, procedures, and challenges. This paper analyzes the most recent breakthroughs in UHS technology and identifies special conditions needed for its successful application, including site selection guidelines, technical and geological factors, and the significance of storage characteristics. The integrity of wells and caprock, which is important for safe and efficient storage, can be affected by the operating dynamics of the hydrogen cycle, notably the fluctuations in pressure and stress within storage formations. To evaluate its potential for broader adoption, we also examined economic elements such as cost-effectiveness and the technical practicality of large-scale storage. We also reviewed current UHS efforts and identified key knowledge gaps, primarily in the areas of hydrogen–rock interactions, geochemistry, gas migration control, microbial activities, and geomechanical stability. Resolving these technological challenges, regulatory frameworks, and environmental sustainability are essential to UHS’s long-term and extensive integration into the energy industry. This article provides a roadmap for UHS research and development, emphasizing the need for further research to fully realize the technology’s promise as a pillar of the hydrogen economy.

Carbon capture and geological sequestration is the only available technology that both allows continued use of fossil fuels in the power sector and reduces significantly the associated CO(2) emissions. Geological sequestration requires a deep permeable geological formation into which captured CO(2)can be injected, and an overlying impermeable formation, called a caprock, that keeps the buoyant CO(2) within the injection formation. Shale formations typically have very low permeability and are considered to be good caprock formations. Production of natural gas from shale and other tight formations involves fracturing the shale with the explicit objective to greatly increase the permeability of the shale. As such, shale gas production is in direct conflict with the use of shale formations as a caprock barrier to CO(2) migration. We have examined the locations in the United States where deep saline aquifers, suitable for CO(2) sequestration, exist, as well as the locations of gas production from shale and other tight formations. While estimated sequestration capacity for CO(2) sequestration in deep saline aquifers is large, up to 80% of that capacity has areal overlap with potential shale-gas production regions and, therefore, could be adversely affected by shale and tight gas production. Analysis of stationary sources of CO(2) shows a similar effect: about two-thirds of the total emissions from these sources are located within 20 miles of a deep saline aquifer, but shale and tight gas production could affect up to 85% of these sources. These analyses indicate that colocation of deep saline aquifers with shale and tight gas production could significantly affect the sequestration capacity for CCS operations. This suggests that a more comprehensive management strategy for subsurface resource utilization should be developed.

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.