Carbon dioxide (CO₂) interacts with rock minerals due to a series of geochemical reactions affecting rock geomechanical properties. These changes in mineralogy, mechanical, and elastic properties weaken the reservoir rock and caprocks. These effects, as consequences, affect the deep saline formation’s mechanical integrity, storage capacity, storage efficiency, and permanence or safety of Carbon Capture and Sequestration (CCS). Generally, CO₂ is injected into the rock continuously in supercritical conditions. Different injection schemes and strategies have been proposed to manage these effects; however, the dynamics of CO₂ interaction when subjected to these strategies are unknown. This paper provides a comprehensive analysis of the geochemical and geomechanical impacts of supercritical CO₂ (scCO₂) on rock formations, employing three distinct injection strategies: Continuous scCO₂ Injection (CCI), Water- Alternating Gas (scCO₂) Injection (WAG), and Simultaneous Water and scCO₂ Aquifer Injection (SAI). Through experimental approaches, the study utilizes core samples from Gray Berea sandstone and Indiana limestone to examine short-term and long-term effects on rock elasticity, strength, and mineralogy. This research assesses the alterations in elastic and mechanical properties by employing a suite of coupled experimental approaches, including core flooding, uniaxial compression testing, and X-Ray Diffraction (XRD). Results demonstrate that different scCO₂ injection strategies significantly affect the rock mechanical integrity and mineral stability due to acidification, geochemical reaction, sequences of the dissolution and precipitation processes, cyclic effect, and mineral hardness. CCI and WAG demonstrate a more favorable impact on the geomechanical properties of both rock types. Conversely, the SAI strategy proves less beneficial, adversely affecting both elastic and mechanical properties despite occurring geochemical reactions. The study highlights the interplay between mineral dissolution and precipitation processes under varying injection conditions, providing insights into optimizing injection schemes to maximize CO₂ storage while maintaining the structural integrity of the geological formations.

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.

The subsurface confinement of anthropogenic carbon dioxide (CO₂) demands robust risk assessment methodologies to identify potential leakage pathways. Legacy wells within the Area of Review (AoR) represent one potential leakage pathway. Robust methodologies require enormous amounts of data, which are not available for many old legacy wells. This study strategically categorizes 4386 legacy wells within the AoR of a potential CO₂ storage site in the Illinois basin and identifies the high-risk wells by leveraging publicly available data—reports and well logs submitted to state regulatory agencies. Wells were categorized based on their proximity to the injection well location, depth, the mechanical integrity of well barriers, and the accessibility to these wells throughout the project lifecycle. Wells posing immediate risks were identified, guiding prioritized corrective actions and monitoring plans. Out of 4386 wells, 54 have high priority for corrective action, 10 have medium priority, and the remainder are of low priority. Case study results from the Illinois basin demonstrate the effectiveness and applicability of this approach, to assess the risk associated with legacy wells within the AoR of potential CO₂ storage site, strategically categorizing over 4000 such wells despite data limitations.

Although gas-lift is an established technology for improving the performances of oil production wells, the simplicity, robustness and accuracy of gas-lift models remain to be fully resolved. As an improvement on the traditional practice, this paper proposes a new approach for modelling the performance of gas-lifted wells at steady-state conditions. The conceptual framework splits the wellbore into two segments. The segments are of unique characteristics, yet they are hydraulically connected. While one segment is controlled primarily by the upstream reservoir-sandface conditions, the dynamics of the second segment are dominated by the lift-gas. This work results in a new four-phase model and an accompanying workflow for analysing the steady-state performance of a gas-lifted well. Using examples from fields operating under diverse conditions in the Niger Delta and North Sea, the new model is validated against a commercial wellbore performance simulator and actual field results. The new model yields average absolute deviation (AAD) of 2.7 and 5.4% against the commercial simulator and field results, respectively. Notwithstanding its relative simplicity, the range of AAD recorded for the new model and workflow attests to its robustness and applicability in practice. In addition to its simple mathematical form, a competitive feature of the proposed model relative to the commercial simulator and most other models is that it accounts for the four phases (gas, oil, water and solid particulates) typically encountered in mature oil production wells and brown fields.