An article by Hart (2011) quoted one of EOG resources recent reports that recovery factor for the Eagle Ford shale play during primary drive reservoir depletion will be roughly 5%. The vast oil remaining stimulates our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. Recent numerical studies have indicated that cyclic gas injection could be an effective method to increase the oil recovery of shale oil reservoirs. Cyclic gas injection could be an effective technique because it is a single-well process; well-to-well connectivity is not required. The hydraulic fracturing provides a large contact area for the injected gas to penetrate and diffuse into the low-permeability matrix. The payback period of the cyclic gas injection process is rather short compared with that of the field- scale flooding process. This makes the single-well cyclic injection process a low-risk process. This paper presents our experimental verification and quantification of the potential of using cyclic CO₂ injection in shale oil reservoirs. This work is the first experimental work to investigate the performance of CO₂ huff-n-puff on shale cores. Core plugs of Mancos and Eagle Ford shales were used. A special lab set up was built to conduct this study. The effects of cyclic time (Soaking Period) and injection pressure on oil recovery, among other parameters, were investigated. Our experimental results showed that cyclic CO₂ injection could increase the recovery factor from 30% to 70% depending on the shale core type. It also shows the effect of the pores connectivity and heterogeneity on the performance of CO₂ huff-n-puff. This study shows that one of the important mechanisms of cyclic gas injection is the pressure effect that causes a large pressure drawdown during the production phase.

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) has been recognized as a pivotal technology for mitigating climate change by reducing CO₂ emissions. Storing CO₂ in deep saline aquifers requires preserving the water-wet nature of the formation throughout the storage period, which is crucial for maintaining rock integrity and storage efficiency. However, the wettability of formations can change upon exposure to supercritical CO₂ (scCO₂), potentially compromising storage efficiency. Despite extensive studies on various factors influencing wettability alteration, a significant research gap remains in understanding the effects of different CO₂ injection strategies on wettability in deep saline formations (DSFs). This study addresses this gap by investigating how three distinct CO₂ injection strategies—continuous scCO₂ injection (CCI), water alternating with scCO₂ injection (WAG), and simultaneous water and scCO₂ injection (SAI)—affect the wettability of gray Berea sandstone and Indiana limestone, both selected for their homogeneous properties relevant to CCS. Using a standardized sessile drop contact angle method before and after CO₂ injection, along with core flooding to model the injection process at an injection pressure of 1500 psi and temperature of 100 °F with a confining pressure of 2500 psi, the results indicate a shift in wettability towards more CO₂-wet conditions for both rock types under all strategies with changes in CA of 61.6–83.4° and 77.6–87.9° and 81.5–124.2° and 94.6–128.0° for sandstone and limestone, respectively. However, the degree of change varies depending on the injection strategy: sandstone exhibits a pronounced response to the CCI strategy, with up to a 77% increase in contact angle (CA), particularly after extended exposure. At the same time, WAG shows the least change, suggesting that water introduction slows surface modification. For limestone, the changes in CA ranged from 9% to 49% across strategies, with WAG and SAI being more effective in altering its wettability. This study underscores the importance of selecting suitable CO₂ injection strategies based on rock type and wettability characteristics to maximize carbon storage efficiency. The findings offer valuable insights into the complex interactions of fluid–rock systems and a guide for enhancing the design and implementation of CCS technologies in various geological settings.