The utilization of supercritical CO₂ in oil and gas reservoir engineering, particularly for enhanced oil recovery, has garnered considerable attention due to its potential to boost hydrocarbon production while reducing CO₂ emissions. This study investigates the improvements achievable in CO₂-enhanced oil recovery and subsequent carbon storage capacity within heterogeneous carbonate reservoirs through supercritical CO₂ miscible injection after seawater flooding. Utilizing a dual-core flooding setup with carbonate core samples exhibiting significant permeability contrast, experiments were conducted under reservoir conditions using live oil, seawater, and supercritical CO₂ miscible injection. To enhance CO₂-enhanced oil recovery and storage within low-permeability zones, a thermal foam gel system was introduced into a highly permeable core after initial supercritical CO₂ miscible injection, effectively sealing off high-permeability zones and improving displacement and storage capacity. Results demonstrate that reservoir heterogeneity notably influences supercritical CO₂-enhanced oil recovery efficiency and sequestration in low permeable regions, with bypass flow in high- permeable regions hindering displacement efficiency and CO₂ storage capacity. However, plugging high-permeability zones using a thermal foam gel system after the initial supercritical CO₂ miscible injection, about 15% extra oil recovery of the pore volume from low-permeability zones was recovered during the second supercritical CO₂ miscible injection, and the equivalent pore space provides a site for storing CO₂ also. Additionally, dynamic characteristic parameters such as injectivity, permeability loss, and endpoint relative permeability related to supercritical CO₂ storage are discussed in this study. The study’s outcomes contribute to advancing the understanding of CO₂-enhanced oil recovery and sequestration, facilitating the development of more effective and sustainable reservoir management practices.

In shale gas reservoir development, determination of hydraulic fracture geometry for horizontal wells is a demanding yet challenging task. One type of approach for hydraulic fracture optimization is based on reservoir simulation. To improve optimization efficiency and accuracy, an automatic and robust procedure integrating the gradient descent method with gas reservoir simulation has been developed. Fractured reservoir models were constructed using the "Multiple INteracting Continua" method, whereby an in-house shale gas reservoir simulator was implemented to model multiple gas transport mechanisms including non-Darcy flow, gas desorption, Klinkenberg effect, and geomechanical effect. The optimization procedure was first validated against two ideal cases and then applied to two realistic cases to optimize fracture spacing, half-length, and dimensionless fracture conductivity. It showed that the optimization results depend on optimization objective, reservoir property, natural fractures, economics and termination criteria. This gradient descent assisted fracture optimization procedure can achieve significant computational reduction and high prediction accuracy for various shale gas reservoir cases.