Carbon Capture and Storage (CCS) is a vital climate mitigation strategy aimed at reducing CO₂ emissions from industrial and energy sectors. This review presents a comprehensive analysis of CCS technologies, focusing on capture methods, transport systems, geological storage, geomechanical and geochemical aspects, modeling, risk assessment, monitoring, and economic feasibility. Among capture technologies, pre-combustion capture is identified as the most efficient (90–95%) due to its high purity and integration potential. Notably, most operational CCS projects in 2025 utilize pre-combustion capture, particularly in hydrogen production and natural gas processing. For geological storage, saline aquifers and depleted oil and gas reservoirs are highlighted as the most promising due to their vast capacity and proven containment. In the transport phase, pipeline systems are considered the most effective and scalable method, offering high efficiency and cost-effectiveness for large-scale CO₂ movement, especially in the supercritical phase. The study also emphasizes the importance of hybrid integrated risk assessment models, such as NRAP-Open-IAM, which combine deterministic simulations with probabilistic frameworks for robust site evaluation. In terms of monitoring, Seismic monitoring methods are regarded as the most reliable subsurface technique for tracking CO₂ plume migration and ensuring storage integrity. Economically, depleted reservoirs offer the most feasible option when integrated with existing infrastructure and supported by incentives like 45Q tax credits. The review concludes that successful CCS deployment requires interdisciplinary innovation, standardized risk protocols, and strong policy support. This work serves as a strategic reference for researchers, policymakers, and industry professionals aiming to scale CCS technologies for global decarbonization.

Increasing concern over climate change has made Carbon Capture and Storage (CCS) an important tool. Operators use deep geologic reservoirs as a form of favorable geological storage for long-term CO₂ sequestration. However, the success of CCS hinges on the integrity of wells penetrating these formations, particularly legacy wells, which often exhibit significant uncertainties regarding cement tops in the annular space between the casing and formation, especially around or below the primary seal. Misalignment of cement plugs with the primary seal increases the risk of CO₂ migrating beyond the seal, potentially creating pathways for fluid flow into upper formations, including underground sources of drinking water (USDW). These wells may not be leaking but might fail to meet the legal requirements of some federal and state agencies such as the Environmental Protection Agency (EPA), Railroad Commission of Texas (RRC), California CalGEM, and Pennsylvania DEP. This review evaluates the impact of CO₂ exposure on cement and casing integrity including the fluid transport mechanisms, fracture behaviors, and operational stresses such as cyclic loading. Findings revealed that slow fluid circulation and confining pressure, primarily from overburden stress, promote self-sealing through mineral precipitation and elastic crack closure, enhancing well integrity. Sustained casing pressure can be a good indicator of well integrity status. While full-physics models provide accurate leakage prediction, surrogate models offer faster results as risk assessment tools. Comprehensive data collection on wellbore conditions, cement and casing properties, and environmental factors is essential to enhance predictive models, refine risk assessments, and develop effective remediation strategies for the long-term success of CCS projects.

Carbon Capture and Storage (CCS) technology presents a practical solution for reducing industrial carbon dioxide (CO₂) emissions through underground anthropogenic CO₂ storage in depleted hydrocarbon reservoirs. The long-term storage efficiency faces several CO₂ leakage challenges that need to be addressed in the planning phase of the CCS project. Thus, effective risk assessment (RA) methodologies are crucial for ensuring safety, regulatory compliance, and public acceptance of CCS projects. This review examines RA parts and their corresponding technical and non-technical challenges. The analysis critically compares over 20 qualitative, semi-quantitative, quantitative, and hybrid RA techniques employed throughout GCS operations. Available quantitative RA tools do not deliver dependable results because they require technical data that become available late in the CCS project development process. Qualitative approaches work well for the initial screening of storage sites with limited data available, yet quantitative methods enable quantification of CO₂ leakage. For the first time, a comparative analysis of two integrated assessment tools is presented in this paper. The techniques achieve success based on high-quality data and analysis of existing technical and non-technical challenges which this paper examines. The comparative analysis outlines the limitations and advantages of every methodology studied and emphasizes the need for integrated hybrid frameworks to boost decision-making in the RA process. Future research should focus on creating or improving existing hybrid frameworks for late-stage RA while utilizing qualitative frameworks in the initial site screening stage to advance GSC’s safe and effective implementation.

Summary: Sand production is one of the major problems that can occur in an oil or gas well. Enzyme-induced carbonate precipitation (EICP) methods have recently emerged as possible environment-friendly solutions for enhancing loose sand consolidation and preventing it from being produced with the fluids to the surface. This work explores increasing the consolidated sand strength and its treatment procedure using a modified EICP. The study also examines the characterization of precipitation generated by microorganisms using a computed tomography (CT) scan. To consolidate the sand specimen, nine different solutions were prepared. The solutions were a mixture of urea, urease, CaCl2, MgCl2, and xanthan gum in varying quantities. X-ray diffraction (XRD) analysis was conducted to determine the type of calcium carbonate (or CaCO3) polymorph. The morphology of calcium carbonate precipitation in the sand sample was visualized through scanning electron microscopy (SEM) imaging. The strength of consolidated samples was determined by the scratch test. The baseline EICP solution was exposed to different curing temperatures, namely, 25°C, 70°C, and 90°C. Out of these temperatures, the sample cured at 70°C showed the maximum strength, while the ones cured at 25°C demonstrated the weakest strength. This outcome emphasizes how crucial temperature control is in determining the strength development of the samples. The results highlight the importance of evaluating how varying curing temperatures affect specimen performance as well as emphasizing the need for accurate temperature control during experimental setups. Interestingly, samples made with a combination of CaCl2 and MgCl2 salts exhibited more strength when compared with EICP solutions formulated with only one type of salt. The consolidated sample that was prepared with xanthan gum with a concentration of 3 g/L showed high strength at 70°C. Notably, this technique offers a cost-effective solution compared with other methods developed to address sand production-related failures in production equipment. Furthermore, CT scans prove to be a valuable tool for investigating the characterization of microbially induced precipitation, including calcite, dolomite, and other minerals. This research underscores the professional approach in evaluating the efficacy of xanthan gum and CT scans in the context of EICP applications.

Nanobubbles (NBs) are emerging as a promising area of research across multiple scientific and industrial domains due to their unique physicochemical characteristics. NBs exhibit distinctive properties compared to normal bubbles, including high internal pressure, a large specific surface area, high interfacial activity, and long-term stability in liquids. Therefore, NBs have gained increasing attention as a novel enhanced oil recovery (EOR) technique, offering potential advantages over traditional gas flooding and chemical flooding. CO₂-NB specifically represents a particularly promising approach as an intersection of EOR and carbon capture, utilization, and storage (CCUS), as CO₂-NB enables hydrocarbon recovery and in situ CO₂ utilization and storage at reservoir conditions. This paper presents a structured comparative discussion of currently identified experimental EOR studies that employ CO₂-NBs. Based on the observations of these experiments, this paper discusses the proposed mechanisms in those experiments or other studies that could scientifically play a role in achieving incremental recovery. The main mechanisms discussed include interfacial tension reduction, wettability alteration, CO₂ transfer from NBs into the oil liquid phase, and suppression of gravity segregation. Other possible contributors discussed in the literature include buoyancy-assisted mobilization, induced shock waves, and drag force reduction. These mechanisms are examined in relation to the distinctive properties of CO₂-NBs, showing how these properties contribute to the occurrence of the proposed mechanisms, showcasing the potential of CO₂-NBs as an emergent EOR–CCUS technology. A preliminary probabilistic assessment was performed to estimate CO₂ storage potential during CO₂-NBs EOR injection. The results suggest that the majority of the injected CO₂ is dissolved in the saturated liquid phase, while the amount of free NBs is negligible, indicating that CO₂-NB injection may provide secure storage through solubility trapping, but with lower storage capacity compared to conventional geological sequestration in saline aquifers.

Underground coal gasification (UCG) requires rigorous geological suitability evaluation to reduce project risks, and scientific site selection is critical for success. Taking the No. 15 coal seam in the Yushe–Wuxiang Block (Qinshui Basin) as the focus, this study evaluates the feasibility of deep UCG using a multi-criteria decision-making framework. A hierarchical evaluation model comprising four primary and 10 secondary geological indicators (e.g., coal thickness, parting coefficient, fault fractal dimension, roof lithology) was constructed. Subjective weights were derived from the Analytic Hierarchy Process (AHP) and combined with objective weights from the coefficient of variation method. The TOPSIS (Technique for Order Preference by Similarity to an Ideal Solution) method was then applied to rank seven development units. Results indicate that the No. 15 coal seam has reasonable potential for UCG implementation. The most favorable areas (Blocks II and VII) are characterized by thick coal seams (>5 m), low parting coefficients (<8%), simple fault networks (fractal dimension ≤0.5–1.05), and competent mudstone roofs. Blocks III, V, and VI are moderately favorable, while Blocks I and IV are marginally favorable. These findings provide a prioritized roadmap for pilot-scale UCG testing in the Yushe–Wuxiang Block.