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.