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The substantial rise in greenhouse gas emissions, especially carbon dioxide (CO 2 ), is causing global warming, sea level rise, and climate change. This situation has prompted a search for effective and environmentally friendly carbon capture, utilization, and storage (CCUS) methods, which are emerging as significant solutions with the potential to reduce CO 2 emissions on a large scale. However, the current methods of CO 2 capture, which are primarily based on absorption techniques, face significant challenges. This involves limited CO 2 capture capacity, degradation of expensive reagents, thermal instability, and high costs associated with separation and purification during the CO 2 capture process, along with the need for energy input for carbon conversion and utilization. In response to these challenges, the application of ionic liquids (ILs) for CO 2 capture has gained increasing interest among scientists. These ILs are characterized by low vaporization, low flammability, high designability, and non-corrosive properties, which make them a viable alternative to traditional CO 2 capture, conversion, and sequestration processes. Hence, the present review offers a comprehensive overview of the fundamental properties of ILs, as well as examining their role in CO 2 capture and conversion, and their applications in enhanced oil recovery (EOR). It examines how the ILs facilitate CO 2 capture through both physical and chemical absorption mechanisms, and explores the influence of the IL structure, particularly the anionic component, on CO 2 solubility. In addition, it explores the use of IL membranes for cost-effective CO 2 separation, and the applications of ILs for reducing the interfacial tension and altering the rock wettability in EOR processes. It highlights how the viscosity of ILs can be chemically tuned to control the CO 2 mobility in sequestration sites, which is an essential feature for enhancing the security and efficiency of carbon capture and storage (CCS) processes. The review also investigates the transformative character of ILs in the catalytic conversion of CO 2 . Specifically, the ILs are characterized by their adaptability and capacity to stabilize reactive intermediates, and are therefore emerging as strong solvents and co-catalysts in the transformation of CO 2 into various important materials, including carbonates, fuels, polymers, and diverse organic compounds. Overall, the review highlights the recent findings and emphasizes the significant potential of ILs in revolutionizing CO 2 capture, conversion, and sequestration. These processes not only reduce CO 2 emissions, but also contribute to the valorization of CO 2 as a feedstock for value-added products. Finally, the review underscores the necessity for further research and development in order to optimize the ILs for practical applications in addressing global greenhouse gas emissions, while also considering their environmental and health impacts. Highlights Physical and chemical absorption mechanisms of ILs. Emergence of ionic liquids (ILs) in CO 2 capture and conversion. Role of ILs in enhanced oil recovery (EOR). Impact of IL structure on CO 2 solubility and separation. ILs in catalytic conversion of CO 2 . Future research directions and environmental consideration.

One of the most demanding environmental and economic challenges of this era is that of supplying the increasing global energy demand while reducing and neutralizing the CO 2 footprint. In this regard, the provision of a secure and diversified energy supply and the sequestration of CO 2 into geological formations are currently of great significance. However, the buoyant nature of CO 2 under the temperature and pressure conditions of typical geological sites leads to the risk of CO 2 leakage, and thus necessitates long-term monitoring. Therefore, the hydrate-based sequestration of CO 2 beneath oceanic sediments has become a desirable alternative to conventional geologic sequestration in some regions, with the potential to eliminate the risks of leaking CO 2 . Over the past decades, considerable progress has been made in the study of gas hydrates, including understanding their occurrence in nature, characterizing their behavior, and assessing their energy and exploitation potentials, along with the potential development of sustainable hydrate-based chemistry applications and technologies. Due to the significance and severity of plugged oil/gas flowlines, the early research was dominated by the inhibition of gas hydrates in order to provide flow assurance in pipelines. However, the discovery of vast natural gas hydrate resources has shifted scientific attention towards the possibility of storing CO 2 as a hydrate, and developing applications such as CO 2 capture and transportation, gas separation, cold storage, natural gas solidification, and CH 4 -CO 2 hydrate replacement. Hence, the present review examines the fundamental properties of gas hydrates, including their natural occurrence and distribution in geological sediments, along with their thermodynamic and kinetic behaviors with respect to the effects of promoting and inhibiting additives. In addition, natural gas hydrate (NGH) production methods and field-scale trials are reviewed. Furthermore, various concepts and experimental investigations pertaining to hydrate-based CO 2 sequestration pathways are reviewed in the final section, including sequestration in the deep ocean, sub-permafrost regions, and marine sediments, as well as the CH 4 -CO 2 hydrate replacement technique. Therefore, CO 2 hydrate storage in suitable depleted oil and gas fields has the potential to reduce infrastructure costs, with CH 4 -CO 2 hydrate replacement potentially providing additional economic incentives. However, long-term field trials in marine sediments with different compositions are required to assess the CO 2 storage potential of hydrate reservoirs, and the effectiveness of CH 4 -CO 2 hydrate replacement technique. Highlights Gas clathrate hydrates enormous energy potential and application for gas storage are introduced. Fundamental properties, occurrence, and geological distribution of gas hydrates are reviewed. Natural gas hydrate (NGH) production methods and field-scale trials are reviewed and discussed. Hydrate-based CO 2 storage pathways and experiments are reviewed and evaluated comprehensively. Field-scale trial of CH 4 -CO 2 hydrate replacement technique is reviewed and discussed. Future research is projected to be on novel techniques that enhance CH 4 -CO 2 replacement efficiency.

Millions of tons of CO 2 are stored annually in geological formations in order to reduce greenhouse gas emissions, relying on caprock as a seal to prevent CO 2 leakage. The wettability of caprock is crucial for its effectiveness, and can be altered by organic acids present in the storage media. The present study investigates the impact of stearic acid on the CO 2 wettability of shale, along with the potential of alumina nanofluids to reverse this effect. Using contact angle measurements, X-ray diffraction, and other analytical methods, the study reveals that stearic acid increases the CO 2 wettability of shale, making it more difficult to contain CO 2 at higher pressures. Specifically, stearic acid-aged shale samples became CO 2 -wet at 16 MPa, thus leading to lower capillary entry pressure and reduced containment capability. However, treatment with alumina nanofluids improves the wettability of shale to intermediate levels, with a 0.25 wt% concentration yielding optimal results. This adjustment also results in positive CO 2 column heights, thus suggesting better containment. The findings demonstrate that alumina nanofluids can enhance CO 2 storage in caprocks by improving the wettability, thus offering a promising approach to the optimization of geological storage solutions for sustainable energy transitions.

Hydrogen, a genuinely clean energy, is a promising alternative to fossil fuels. Inspired by underground gas storage of methane, establishing underground hydrogen storage (UHS) in depleted oil and gas reservoirs has emerged as a significant research focus. Carbonate reservoirs, where widely-presented fractures can facilitate the high-speed injection and production of gases, are hence ideal candidates for building underground hydrogen storage facilities. During the cyclic injection and extraction processes of UHS, the formation is subjected to stress disturbances, leading to stress sensitivity. Understanding the stress sensitivity patterns of carbonate rocks is crucial for optimizing injection and production strategies. This study reconstructed three-dimensional digital models of fractured carbonate rocks from the L gas field using micro-CT scanning technology. Utilizing the finite element method, we investigated the microscopic permeability characteristics of carbonate rocks and analyzed the impact of stress loading direction and confining stress on stress sensitivity. The findings reveal that the stress loading direction significantly influences the stress sensitivity of fractured carbonate rocks. When a stress of 60 MPa is applied perpendicular to the fracture direction, the permeability reduction ratio can reach 17.32%. In contrast, when the same stress is applied parallel to the fracture direction, the permeability reduction ratio is only 4.82%. Furthermore, a simulation of UHS with cyclic injection and production of H 2 in the target block was conducted. When both permeability and porosity stress sensitivity were considered, the working gas volume for UHS decreased by only 3.4%, demonstrating that fractured carbonate reservoirs are feasible candidates for constructing underground hydrogen storage.

Understanding the wettability of carbon dioxide (CO 2 ) and the interfacial properties between reservoir rocks and fluids is crucial for the effective geological carbon sequestration (GCS). The most accurate way to measure these properties is the laboratory experiments under simulated reservoir conditions. However, experimental measurement of CO 2 wettability in storage/caprock, influenced by thermo-physical conditions, poses significant challenges due to the reactivity and embrittlement risks associated with high levels of CO 2 . Therefore, data-driven machine learning (ML) models can be used as an alternative to laboratory experiments to predict rock/CO 2 /brine wettability in a precise and less hazardous manner. In this study, we have used multiple ML models, including stacked generalization regression (SGR), gradient boosting, and tree-based models, to estimate the wettability of Saudi Arabian (SA) basalt within a ternary system involving rocks, CO 2 , and brine, operating under diverse conditions. To improve the accuracy of the ML models, a comprehensive set of experimental data was collected from the literature that covered a wide range of pressure and temperature, 0.1–25 MPa and 298–343 K, respectively. Various data exploration methods, such as heatmaps, and histograms were used to thoroughly examine the laboratory dataset. The ML models were trained to predict the advancing and receding contact angles. The results showed that the proposed ML models could accurately forecast wettability behaviors across diverse operational conditions with an average R 2 score of above 0.996. The outcomes of ML models can be highly useful for accurately determining the CO 2 wettability. This information is crucial for defining the storage capacity and assessing containment security in large-scale CO 2 sequestration projects.

The fracture volume is gradually changed with the depletion of fracture pressure during the production process. However, there are few flowback models available so far that can estimate the fracture volume loss using pressure transient and rate transient data. The initial flowback involves producing back the fracturing fluid after hydraulic fracturing, while the second flowback involves producing back the preloading fluid injected into the parent wells before fracturing of child wells. The main objective of this research is to compare the initial and second flowback data to capture the changes in fracture volume after production and preload processes. Such a comparison is useful for evaluating well performance and optimizing fracturing operations. We construct rate-normalized pressure (RNP) versus material balance time (MBT) diagnostic plots using both initial and second flowback data (FB i and FB s , respectively) of six multi-fractured horizontal wells completed in Niobrara and Codell formations in DJ Basin. In general, the slope of RNP plot during the FB s period is higher than that during the FB i period, indicating a potential loss of fracture volume from the FB i to the FB s period. We estimate the changes in effective fracture volume ( V ef ) by analyzing the changes in the RNP slope and total compressibility between these two flowback periods. V ef during FB s is in general 3%–45% lower than that during FB i . We also compare the drive mechanisms for the two flowback periods by calculating the compaction-drive index (CDI), hydrocarbon-drive index (HDI), and water-drive index (WDI). The dominant drive mechanism during both flowback periods is CDI, but its contribution is reduced by 16% in the FB s period. This drop is generally compensated by a relatively higher HDI during this period. The loss of effective fracture volume might be attributed to the pressure depletion in fractures, which occurs during the production period and can extend 800 days.