Cyclic solvent injection, known as solvent huff-n-puff, is one of the promising techniques for enhancing oil recovery from shale reservoirs. This study investigates the huff-n-puff performance in ultratight shale reservoirs by conducting large-scale numerical simulations for a wide range of reservoir fluid types (retrograde condensate, volatile oil, and black oil) and different injection gases (CO₂, C₂H₆, and C₃H₈). A dual-porosity compositional model is utilized to comprehensively evaluate the impact of multicomponent diffusion, adsorption, and hysteresis on the production performance of each reservoir fluid and the retention capacity of the injection gases. The results show that the huff-n-puff process improves oil recovery by 4–6% when injected with 10% PV of gas. Huff-n-puff efficiency increases with decreasing gas-oil ratio (GOR). C₂H₆ provides the highest recovery for the black oil and volatile oil systems, and CO₂ provides the highest recovery for retrograde condensate fluid type. Diffusion and adsorption are essential mechanisms to be considered when modeling gas injection in shale reservoirs. However, the relative permeability hysteresis effect is not significant. Diffusion impact increases with GOR, while adsorption impact decreases with increasing GOR. Oil density reduction caused by diffusion is observed more during the soaking period considering that the diffusion of the injected gas caused a low prediction error, while adsorption for the injected gas showed a noticeable error.

Statistical education is a crucial yet often overlooked aspect of AI in higher education. However, traditional approaches usually focus heavily on procedural knowledge, leaving students anxious about statistics and less confident in applying concepts to real-world problems. This study examines a method that enhances statistical learning outcomes by integrating data visualization and gamification strategies. Students were randomly assigned to either a control group (CG) or an intervention group (IG), and each group was further divided into teams. The curriculum was enhanced in a college statistics course offered for both engineering and math majors. IG students applied data visualization and gamification in a hands-on group project aimed at solving a real-world problem and competed as they presented their results. The effectiveness of this approach was assessed through statistical analyses comparing the performance of IG and CG in surveys, final grades, and project grades. The results from evaluation methods indicated that IG students outperformed CG students, demonstrating a positive impact of gamification on statistics education.

Gas injection is a well-established method for enhancing oil recovery by improving oil mobility, primarily through viscosity reduction. While its application in heavy oil reservoirs is extensively studied, the specific impact of carbon dioxide (CO₂) injection pressure on fluid viscosity reduction and the ultimate recovery factor from light oil reservoirs has not been fully investigated. To address this gap, this experimental study systematically explores the effects of CO₂ injection pressure and reservoir permeability on light oil recovery. This study conducted miscible, near-miscible, and immiscible gas injection experiments on two core samples with distinct permeabilities (13.4 md and 28 md), each saturated with light oil. CO₂ was injected at five different pressures, including conditions ranging from immiscible to initial reservoir pressure. The primary metrics for evaluation were the recovery factor (measured at gas breakthrough, end of injection, and abandonment pressure) and the viscosity reduction of the produced oil. The results conclusively demonstrate that CO₂ injection significantly enhances light oil production. A direct proportional relationship was established between both the injection pressure and the recovery factor and between permeability and overall oil production at the gas breakthrough. However, a key finding was the inverse relationship observed between permeability and viscosity reduction: the lower-permeability sample (13.4 md) consistently exhibited a greater percentage of viscosity reduction across all injection pressures than the higher-permeability sample (28 md). This unexpected trend is aligned with the inverse relationship between the permeability and the recovery factor after the gas breakthrough. This outcome suggests that enhanced CO₂ solubility, driven by higher confinement pressures within the nanopores of the lower-permeability rock, promotes a localized, near-miscible state. This effect was even evident during immiscible injection, where the low-permeability sample showed a noticeable viscosity reduction and superior long-term production. These findings highlight the critical role of pore-scale confinement in governing CO₂ miscibility and its associated viscosity reduction, which should be incorporated into enhanced oil recovery design for unconventional reservoirs.