Prolonged gas hydrate exploitation induces reservoir creep, leading to pore structure deformation, permeability reduction, and elevated risks of wellbore instability, ultimately impeding sustainable resource recovery. Accurate modeling of permeability evolution in hydrate-bearing sediments (HBS) under creep conditions is therefore crucial. However, the non-uniform distribution and irregular morphology of sediment particles complicate pore structures and fluid pathways, posing significant challenges for prediction. This study proposes a novel theoretical permeability model for HBS that incorporates the degree of non-uniform particle distribution, particle shape, pore structure creep, hydrate saturation, and hydrate pore morphology. Model validation against public datasets confirms its predictive capability. Sensitivity analysis reveals that pore structure creep, the degree of non-uniform particle distribution, and particle shape significantly influence permeability, with increased non-uniformity or larger particle aspect ratios leading to reduced permeability. For instance, after 40 h of creep, permeability decreases from 5 to 1.3 mD as the damage-related parameter β increases from 0.4 to 1.0. The proposed model advances understanding of permeability evolution in HBS and provides a theoretical basis for the long-term development of natural gas hydrates.

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.