Estimation of CO2-Brine InterfacialTension Based on an Advanced Intelligent Algorithm Model: Applicationfor Carbon Saline Aquifer Sequestration

CO2 storage in saline aquifers: A simulation on quantifying the impact of permeability heterogeneity

S13 Meta-analysis of gene-expression profiles: towards a unified understanding of breast cancer sub-typing and prognosis

Carbon dioxide (CO_2) geological storage in deep saline aquifers is a key measure to mitigate global warming. However, it still faces a variety of technical challenges such as enhancing CO_2 effective storage capacities. In this paper, a preliminary model is developed to simulate CO_2 migration during nanofluid-based supercritical CO_2 geological storage in saline aquifers. The main mechanisms, including Brownian motion, thermophoresis, thermal energy transfer, and interfacial tension, are included in the proposed conceptual model. Based on the high-resolution space-time conservation element and solution element (CE/SE) method, the model is used to simulate CO_2 migration and distribution in the in-situ heterogeneous saline aquifer. It can be inferred that the involvement of nanoparticles decreases shear stresses opposing flow and enhances CO_2 mobility in the flow boundary layer. In addition, nanoparticles increase shear stresses outside the boundary layer and retard CO_2 velocity. These competitive mechanisms result in homogeneous migration of CO_2 in the saline formation. One preliminary suggestion is that nanofluids enhance homogeneous CO_2 transport in the reservoir and mitigate the negative effects of stratigraphic heterogeneity on migration and accumulation of the CO_2 plume. CO_2 effective storage capacity may be greatly elevated by means of nanofluid-based CO_2 geological sequestration. The concept of nanofluid-based CO_2 geological storage may be potentially conducive to large-scale commercial CO_2 geological storage and useful for exploration of geothermal resources in deep-seated hot rocks. The effects of CO_2 solubility and geochemical reactions on nanofluid flows may be considered in a future study.

To support the European Green Deal and accelerate climate mitigation, the CCUS ZEN project conducted a high-level technical screening of Carbon Capture, Utilization, and Storage (CCUS) value chains in the Baltic and Mediterranean regions. These regions were chosen, since they have lower maturity levels for CCUS compared with the current development in the North Sea region. The study mapped industrial carbon dioxide (CO2) emission sources, potential storage sites, transport infrastructure, and utilization options. Emission clusters and hubs were identified based on volume, location, and industry type, while for each mapped storage site, information was gathered about the type of reservoir (deep saline aquifer or depleted hydrocarbon field), the onshore or offshore location, the capacity of the reservoir and the Storage Readiness Level, indicating the maturity of the capacity evaluation. Transport options included pipelines, shipping, and multimodal solutions were presented. This study defined unique high-level technical CCUS value chain screening workflow for mapping of emitters, infrastructures to storage screening. An open geographical information system was used for mapping the emitters and storage sites from previous reports, and to illustrate emission clusters and possible transport routes, both existing and future infrastructures. The screening revealed significant CO2 emission sources and storage capacities across the regions, with notable clusters in Poland, Germany, Italy, and Turkey. The Baltic region showed three times the storage capacity of the Mediterranean region. Eight promising CCUS value chains were defined, integrating source-sink matching and infrastructure feasibility. A detailed case study of Southern Italy and Greece was presented, to demonstrate the potential for regional CCUS deployment, highlighting challenges such as data availability, storage capacity uncertainty, transport possibilities and stakeholder coordination. This study will provide a foundation for further development and stakeholder engagement in CCUS planning across Europe.

Geological CO2 sequestration (GCS) has been proposed as an effective approach to mitigate carbon emissions in the atmosphere. Uncertainty and sensitivity analysis of the fate of CO2 dynamics and storage are essential aspects of large-scale reservoir simulations. This work presents a rigorous machine learning-assisted (ML) workflow for the uncertainty and global sensitivity analysis of CO2 storage prediction in deep saline aquifers. The proposed workflow comprises three main steps: The first step concerns dataset generation, in which we identify the uncertainty parameters impacting CO2 flow and transport and then determine their corresponding ranges and distributions. The training data samples are generated by combining the Latin Hypercube Sampling (LHS) technique with high-resolution simulations. The second step involves ML model development based on a data-driven ML model, which is generated to map the nonlinear relationship between the input parameters and corresponding output interests from the previous step. We show that using Bayesian optimization significantly accelerates the tuning process of hyper-parameters, which is vastly superior to a traditional trial–error analysis. In the third step, uncertainty and global sensitivity analysis are performed using Monte Carlo simulations applied to the optimized surrogate. This step is performed to explore the time-dependent uncertainty propagation of model outputs. The key uncertainty parameters are then identified by calculating the Sobol indices based on the global sensitivity analysis. The proposed workflow is accurate and efficient and could be readily implemented in field-scale CO2 sequestration in deep saline aquifers.

Summary Emission of carbon dioxide into the atmosphere from various industrial resources, accounts for most of greenhouse gases ( Gershenzon et al. 2017 ). To reduce the amount of carbon dioxide emission from these sources, Carbon Capture and Storage (CCS) is the main approach by storing the CO2 in deep saline aquifers and several other geological structures. It should be noted that the relative permeability hysteresis has a great impact on the transport of fluids and distribution pattern of phases ( Al-Khdheeawi et al. 2017 ). Literature review shows that, the concept of relative permeability hysteresis in CO2 storage processes and its effect on trapping of carbon dioxide is still an open area for research. Here we thus investigate the effect of hysteresis on movement of CO2 plume in vertical direction and dissolution and residual trapping of CO2.

The development of large-scale, flexible, and safe hydrogen storage is critical for enabling a low-carbon energy system. Deep saline aquifers (DSAs) offer substantial theoretical capacity and broad geographic distribution, making them attractive options for underground hydrogen storage. However, hydrogen storage in DSAs presents complex technical, geochemical, microbial, geomechanical, and economic challenges that must be addressed to ensure efficiency, safety, and recoverability. This study synthesizes current knowledge on hydrogen behavior in DSAs, focusing on multiphase flow dynamics, capillary trapping, fingering phenomena, geochemical reactions, microbial consumption, cushion gas requirements, and operational constraints. Advanced numerical simulations and experimental observations highlight the role of reservoir heterogeneity, relative permeability hysteresis, buoyancy-driven migration, and redox-driven hydrogen loss in shaping storage performance. Economic analysis emphasizes the significant influence of cushion gas volumes and hydrogen recovery efficiency on the levelized cost of storage, while pilot studies reveal strategies for mitigating operational and geochemical risks. The findings underscore the importance of integrated, coupled-process modeling and comprehensive site characterization to optimize hydrogen storage design and operation. This work provides a roadmap for developing scalable, safe, and economically viable hydrogen storage in DSAs, bridging the gap between laboratory research, pilot demonstration, and commercial deployment.

Water content of carbon dioxide (CO2) is an important parameter in engineering applications, such as CO2 storage in deep saline aquifers and enhanced oil recovery processes. Large numbers of experimental data have been reported on the solubility of CO2 in brine. However, experimental data on the water content of CO2 in equilibrium with formation brine are not reported in the literature. Water content of natural gas is traditionally calculated by general water content charts; however, these charts are not available for CO2 in equilibrium with formation brine. In this work, using an accurate fugacity and activity model available in the literature, an efficient and simple procedure is developed to estimate the water content of CO2 in equilibrium with formation brine. To validate the developed procedure, the predicted CO2 rich phase water content is compared with the reported experimental data in the literature and other predictive models for CO2-water systems. A CO2 water content chart is presented that can be used simply to predict the water content of CO2 in equilibrium with formation brine. The procedure presented may be used for generating necessary input data for flow simulation of CO2 storage in deep saline aquifers.

Underground storage of carbon dioxide (CO2) in geological formations plays a vital role in carbon capture and storage (CCS) technology. It involves capturing CO2 emissions from industrial processes and power generation and storing them underground, thereby reducing greenhouse gas emissions and curbing the impact of climate change. This review paper features a comparative analysis of CO2 storage in deep saline aquifers, depleted reservoirs, coal seams, basaltic formations and clastic formations. The comparison has been drawn based upon seven factors carefully selected from the literature, i.e., safety, storage capacity, injection rates, efficiency, residual trapping, containment and integrity and potential to improve, and all of these factors have been rated from low (1) to high (5) based upon their individual traits. Based upon these factors, an overall M.H. rating system has been developed to categorize geological formations for CO2 storage and it is observed that deep water aquifers and basaltic formations are the most effective options for CO2 storage. Lastly, a detailed way forward has been suggested, which can help researchers and policymakers to find more viable ways to enhance the efficiency of CO2 storage in various geological formations.

Geological CO2 sequestration (GCS) has been a practical approach used to mitigate global climate change. Uncertainty and sensitivity analysis of CO2 storage capacity prediction are essential aspects for large-scale CO2 sequestration. This work presents a rigorous machine learning-assisted workflow for the uncertainty and global sensitivity analysis of CO2 storage capacity prediction in deep saline aquifers. The proposed workflow comprises three main steps: 1) dataset generation — we first identify the uncertainty parameters that impact CO2 storage in deep saline aquifers and then determine their corresponding ranges and distributions. We generate the required data samples by combining the Latin Hypercube Sampling (LHS) technique with high-resolution simulations. 2) surrogate development — a data-driven surrogate is developed to map the nonlinear relationship between the input parameters and corresponding output interests from the previous step. The implementation of Bayesian optimization accelerates the tunning process of hyper-parameters instead of traditional trial-error analysis. 3) uncertainty and global sensitivity analysis — Monte Carlo simulations based on the optimized surrogate are performed to explore the time-dependent uncertainty propagation of model outputs. Then the key contributors are identified by calculating the Sobol indices based on the global sensitivity analysis. The proposed workflow is accurate and efficient and could be readily implemented in field-scale CO2 sequestration in deep saline aquifers.

Carbon capture, utilization, and storage (CCUS) consists of several technologies that are capable of playing significant and diverse roles in the achievement of global energy and climate goals under the context of energy transition. It forms a relevant technological approach for capturing carbon and delivering a net zero energy system. Currently, CCUS projects are mainly taking place in developed countries, with some of them having specific promotion policies such as 45Q under IRA in the US. Several of the current CCUS activities take the form of enhanced oil recovery (EOR). CCS have a value chain comprising the CO2 capture, compression and liquefaction, transportation (by pipeline or ships), and storage (e.g., underground in saline aquifer or depleted reservoirs). CCU shares some of the CCS value chain elements, except storage, as it consists of techniques and initiatives that convert captured emitted carbons into useful products. Hence, adopting a qualitative research methodology, this study explores the concept and relevancy of CCUS in achieving net zero emissions using hydrogel as a case study. This study aims for the implementation of a new CCUS value chain that involves products based on carbon sequestration in land-based carbon dioxide removal (CDR), leading to a high potential for mitigating carbon emissions. Consequently, CCUS is vital to attenuate the problems of climate change, as it plays a key role in decarbonizing and facing the challenge of anthropogenic CO2 emissions, in addition to providing a long-term alternative compatible with sustainable development. Based on its properties and characteristics, especially as a polymeric electrolyte with a high capacity for conducting physical separation, this study proposes hydrogel as a viable technique for the maximum capture of atmospheric carbon. Such captured carbon is then utilized for various applications or stored appropriately. This study concludes with a highlight of specific lessons learned in this regard, and the major challenges observed with this CCUS technique.

The U.S. Department of Energy’s (DOE) FutureGen 2.0 Program involves two projects: (1) the Oxy-Combustion Power Plant Project and (2) the CO2 Pipeline and Storage Project. This Final Technical Report is focused on the CO2 Pipeline and Storage Project. The FutureGen 2.0 CO2 Pipeline and Storage Project evolved from an initial siting and project definition effort in Phase I, into the Phase II activity consisting permitting, design development, the acquisition of land rights, facility design, and licensing and regulatory approvals. Phase II also progressed into construction packaging, construction procurement, and targeted early preparatory activities in the field. The CO2 Pipeline and Storage Project accomplishments were significant, and in some cases unprecedented. The engineering, permitting, legal, stakeholder, and commercial learnings substantially advance the nation’s understanding of commercial-scale CO2 storage in deep saline aquifers. Voluminous and significant information was obtained from the drilling and the testing program of the subsurface, and sophisticated modeling was performed that held up to a wide range of scrutiny. All designs progressed to the point of securing construction contracts or comfort letters attesting to successful negotiation of all contract terms and willing execution at the appropriate time all major project elements – pipeline, surface facilities, and subsurface – as well as operations. While the physical installation of the planned facilities did not proceed in part due to insufficient time to complete the project prior to the expiration of federal funding, the project met significant objectives prior to DOE’s closeout decision. Had additional time been available, there were no known, insurmountable obstacles that would have precluded successful construction and operation of the project. Due to the suspension of the project, site restoration activities were developed and the work was accomplished. The site restoration efforts are also documented in this report. All permit applications had been submitted to all agencies for those permits or approvals required prior to the start of project construction. Most of the requisite permits were received during Phase II. This report includes information on each permitting effort. Successes and lessons learned are included in this report that will add value to the next generation of carbon storage efforts.

During CO2 storage in deep saline aquifers, the presence of residual water has an important influence on the storage efficiency and safety. In this study, natural rock cores taken from deep reservoirs in the Ordos Basin and Fukang, Xinjiang are used as research objects. Nine groups of core‐flooding experiments are performed under different CO2/N2 gas mixture ratios to study the influence of rock properties (mineral composition, permeability, porosity and pore structure) on the residual water. Furthermore, the geophysical and chemical properties of rock cores are analyzed by X‐ray diffraction, electron microscopy, field emission scanning electron microscopy and piezoelectric mercury method. The results show that residual water saturation is a quantitative power function of drainage time. The residual water saturation is positively correlated with the total amount of quartz and feldspar and increases with increasing permeability. Moreover, both the average and median pore throat radius show a strong inverse correlation with irreducible residual water saturation; as these radius increase, the residual water saturation decreases. In contrast, the porosity and maximum pore throat radius display a weaker correlation with irreducible residual water saturation. This study is of great value for engineering practices such as the site selection of CO2 storage projects in saline aquifer and improvement of CO2 storage efficiency. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

CO2 storage in deep saline aquifers is considered a possible option for mitigation of greenhouse gas emissions from anthropogenic sources. Understanding of the underlying mechanisms, such as convective mixing, that affect the long‐term fate of the injected CO2 in deep saline aquifers, is of prime importance. We present scaling analysis of the convective mixing of CO2 in saline aquifers based on direct numerical simulations. The convective mixing of CO2 in aquifers is studied, and three mixing periods are identified. It is found that, for Rayleigh numbers less than 600, mixing can be approximated by a scaling relationship for the Sherwood number, which is proportional to Ra1/2. Furthermore, it is shown that the onset of natural convection follows tDc∼Ra−2 and the wavelengths of the initial convective instabilities are proportional to Ra. Such findings give insight into understanding the mixing mechanisms and long term fate of the injected CO2 for large scale geological sequestration in deep saline aquifers. In addition, a criterion is developed that provides the appropriate numerical mesh resolution required for accurate modeling of convective mixing of CO2 in deep saline aquifers. © 2007 American Institute of Chemical Engineers AIChE J, 2007

This review provides a comprehensive examination of Carbon Capture, Utilization, and Storage (CCUS) technologies, focusing on their advancements, challenges, and future prospects. It begins with an overview of carbon capture methods, including pre-combustion, post-combustion, and oxy-fuel combustion techniques, highlighting recent technological improvements and associated challenges. The review then explores various carbon utilization strategies, such as chemical conversion, biological processes, and mineralization, discussing emerging technologies, potential applications, and the economic and environmental benefits of utilizing captured CO 2 . The discussion on carbon storage covers geological options like saline aquifers and depleted oil and gas fields, as well as recent advancements in monitoring and safety measures. The review assesses long-term stability and the risks linked to CO2 storage. In addressing the integration and optimization of CCUS systems, it evaluates the synergies between capture, utilization, and storage, includes techno-economic analyses of integrated systems, and presents case studies of successful CCUS projects. Economic feasibility and scalability are scrutinized through cost analysis, barriers to large-scale implementation, and the role of policy and regulatory frameworks. The review also identifies key research gaps, explores innovation potential, and provides strategic recommendations for advancing CCUS adoption. In conclusion, the findings underscore the essential role of CCUS in mitigating climate change, while highlighting the need for continued innovation, policy support, and cost reductions to enable its widespread deployment and effectiveness.