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Natural gas hydrates have attracted global attention as a potential widespread energy resource. The permeability of gas-hydrate-bearing natural sediments has been investigated using conventional cores (C-cores), pressure cores (P-cores), well-logging nuclear magnetic resonance (NMR), formation pressure tests (FPT), and history-matching simulations (HiM), which obtain near in situ permeability values. However, deviations and the relative accuracies of these permeability analysis methods, as well as the reasons for high permeability characteristics in such resources, have been largely ignored. Here, we analyze the relative accuracies of permeability analysis methods combined with the analytic hierarchy process (AHP) method, then review permeability investigations of in situ gas hydrate-bearing natural sediments at various sites. The permeability data obtained are then compared with the Tokyo model to determine the permeability reduction exponent N. Finally, we discuss the reasons for high permeability characteristics and present current research challenges, solutions, and future prospects. We identified the P-core method as the most accurate, followed by well-logging NMR, FPT, C-cores, and HiM (ranked in sequence). Values of N < 1.25 indicate sediment heterogeneity and the presence of preferential flow channels. We found high permeability characteristics associated with high sand content layers in silty or sandy silty hydrate-bearing sediments, which are commonly found in marine environments. Matching parameters of well-logging NMR that do not accurately reflect silt depth profiles may result in low permeability estimates in high sand content layers. Researching the microscale characteristics of sediment heterogeneity and preferential flow channels is strongly recommended to explore the reasons for differences between these methods.
Xu et al. (Sat,) studied this question.