This study investigates the impact of CO₂-enhanced oil recovery (CO₂-EOR) on the petrophysical properties and oil recovery potential of sandstone reservoirs in the oilfields located in the east-southern Precaspian region of Kazakhstan. Despite the recognized potential of CO₂-EOR for improving oil recovery and aiding carbon sequestration, there is limited understanding of how CO₂-EOR specifically affects the petrophysical properties of sandstone reservoirs in this region. Laboratory experiments were conducted using two core samples from the selected oilfields to examine changes in porosity, permeability, and oil recovery coefficients. The results demonstrated that porosity changes ranged from a slight increase of 1.1% to a decrease of 1.5%, while permeability reduction was significant, with decreases ranging from 29% to 50% due to clay alteration and halite precipitation. The oil recovery coefficient after CO₂ flooding was found to be between 0.49 and 0.54. These findings underscore the complex interactions between CO₂ and reservoir rocks, emphasizing the need for tailored EOR strategies in different geological settings.

Enhanced oil recovery (EOR) techniques are essential for maximizing hydrocarbon extraction from mature reservoirs. CO₂ injection (CO₂-EOR) is a promising technology that improves oil recovery while contributing to greenhouse gas reduction. This study investigates the potential of miscible CO₂-enhanced oil recovery (CO₂-EOR) in the MakXX oilfield of southeastern Kazakhstan. The aim is to assess oil displacement efficiency and its impact on key rock properties, including porosity, permeability, and mineral composition, under reservoir conditions. Core flooding experiments were conducted at 13 MPa and 42 °C using high-precision equipment to replicate reservoir conditions. The core was analyzed before and after CO₂ injection using SEM, EDS, and XRD. The results revealed a 54% oil recovery efficiency, accompanied by a 19% decrease in permeability and 8% reduction in porosity due to mineral precipitation and clay transformation. These findings provide insight into the performance and limitations of CO₂-EOR and support its application in similar lithology. To confirm and upscale laboratory observations, numerical simulation was conducted using a compositional model. The results demonstrated improved oil recovery, pressure stabilization, and enhanced sweep efficiency under CO₂ injection, supporting the scalability and field applicability of the proposed EOR approach.

Enhanced oil recovery (EOR) selection requires reservoir performance simulation that reproduces not only production trends but also the physical mechanisms controlling pressure, fluid behavior, multiphase flow, gas mobility, well constraints, and long-term reservoir response. This study presents a reservoir performance simulation and process-to-simulator quality-control workflow for CO₂-based EOR evaluation in anonymized carbonatecontaining Field X, Kazakhstan. The field-scale simulation uses a three-dimensional ECLIPSE E300 compositional model with 93 × 88 × 78 grid cells, 194,413 active cells, and a 40-year forecast period. The framework integrates compositional pressure-volume-temperature/equation-of-state (PVT/EOS) behavior, minimum miscibility pressure (MMP), three-phase relative permeability, hysteresis, vertical connectivity and gravity override, injection scheduling, bottomhole-pressure (BHP) control, wellbore thermal response, CO₂ tracking, and mass-balance verification. Each mechanism is linked to a simulator functional block, diagnostic output, sensitivity test, and acceptance criterion. A representative ECLIPSE E300 process-to-code sequence – RUNSPEC, GRID, PROPS, SOLUTION, SCHEDULE, SUMMARY, followed by MATLAB post-processing – provides traceability from reservoir physics to forecast interpretation. Sensitivity analysis identifies vertical connectivity, gas relative permeability, MMP uncertainty, fault transmissibility, hysteresis, and BHP constraints as the principal controls on simulated reservoir performance. Continuous CO₂ injection increases cumulative oil production from 17.96 to 25.37 Mt, yielding 7.41 Mt of incremental oil (+41.3%); at year 40, the CO₂ case maintains 238.6 t/d while the Base case declines to zero. The results demonstrate that reservoir performance simulation provides a rigorous engineering basis for forecasting reservoir behavior, quantifying model sensitivity, validating physical consistency, and supporting defensible EOR method selection.

Carbon dioxide-enhanced oil recovery is applied across reservoir systems with markedly different lithologies and flow architectures. In this review, the analyzed scope includes terrigenous (siliciclastic) reservoirs, carbonate reservoirs, carbonate-bearing sandstones and mixed siliciclastic-carbonate systems, particularly where recovery is constrained by unfavorable fluid mobility, geological heterogeneity, channeling, variable wettability or limited injectivity. Carbon dioxide is attractive because dissolution in oil can promote swelling, viscosity reduction, interfacial-tension reduction and pressure support, but these benefits may be offset by early gas breakthrough, gravity segregation, pressure below the minimum miscibility pressure, rock-brine-fluid interactions, corrosion or unfavorable project economics. Eighteen experimental, numerical and decision-oriented publications from 2022-2025 were critically synthesized. The analysis shows that continuous carbon dioxide injection, cyclic injection, water-alternating-gas and carbon dioxide foam should be treated as related design options rather than isolated technologies. Their ranking depends on fluid response, pressure relative to minimum miscibility pressure, lithology and pore architecture, reservoir heterogeneity, gas mobility, injectivity and the quality of laboratory-to-model transfer. The review does not assume identical behavior across lithologies; instead, mineralogy, wettability, pore structure and fracture connectivity are treated as transferability controls. Alternative chemical, engineered-water and thermal methods are retained as benchmarks defining the limits of carbon dioxide applicability. A staged workflow links core evidence, rock-brine-fluid compatibility, compositional simulation, uncertainty analysis and techno-economic screening before pilot or full-field decisions.

Enhanced oil recovery (EOR) screening is commonly initiated from reservoir and fluid properties, displacement mechanisms, and expected recovery potential. In technically complex offshore systems, however, a candidate method may be unsuitable for further development if the associated fluids and operating conditions intensify corrosion, inorganic scaling, organic deposition, emulsion persistence, phase instability, or near-wellbore damage. This study develops an integrity-constrained pre-pilot laboratory screening workflow for the integrated Field X-Field Y system. The workflow integrates brine chemistry and water-compatibility calculations, corrosion and inhibitor tests, wax-appearance-temperature (WAT) and viscosity data, emulsion stability, PVT recombination, and filtration compatibility. Untreated corrosion rates reached 11.586 mm/year at the electrical submersible pump outlet and 2.942 mm/year at the wellhead. Field X-Field Y formation-water mixing was compatible at 60 °C, whereas cooling to 30–50 °C increased predicted BaSO4-dominated precipitation, with 18.849 mg/L at 30 °C for the 75/25 mixture; the broader marine-water case reached 58.79 mg/L under the evaluated low-temperature/low-pressure condition. Field Y DST-1 was the most restrictive oil in the organic-deposition screen, with 10.6 wt.% paraffin and WAT evidence spanning 17.4–22.4 °C. Artificial emulsions retained up to 70% water for Field X DST-3 and 80% for Field Y DST-1. For the selected associated-gas analogue, a gas-oil ratio not above 90 m³/t at 18 MPa and 60.5 °C was used as the single-phase recombination boundary. The six-domain matrix was reformulated as an equal-weight ordinal qualification-burden index rather than a recovery-ranking tool; WAG had the highest burden (S=15; R=2.50), and this position remained unchanged under ±25% one-at-a-time criterion-weight perturbations. The framework therefore identifies operational-integrity constraints and the laboratory qualification required before direct displacement corefloods, compositional simulation, and pilot validation; it does not quantify incremental oil recovery.