Accurate estimation of permeability for reservoir simulation and production is challenging in carbonate rocks due to the diversified pore structures resulting from deposition and diagenetic modification. A significant amount of residue gas is expected in the Puguang field, China. We use a shear-frame flexibility factor γμ from a rock-physics model as an index to quantify its spatial variation of pore structure and constrain the estimation of permeability in this field. The pore-structure index γμ is established and used to classify various permeability-porosity trends at well locations where core and log data are available. It is found that when γμ>4, the pore type is dominated by intercrystalline pores with large pore-throat sizes and high connectivity, the permeability-porosity relation is κ=Aϕ3+Bϕ2+Cϕ+D; when γμ<4, the pore type consists of isolated moldic pores, the permeability-porosity relation is κ=EϕF, where A, B, C, D, E, and F are constants, which are 80, 18, 3, 0.004, 5.5, and 1.6, respectively, for the studied gas reservoir. Rock-physics-based seismic inversion is then applied to quantify the spatial variation of pore type and permeability. The inversion results indicate that regional stratigraphy has a paramount control on the distribution of pore type and permeability. Moldic pores (γμ<4) are widely distributed near the unconformities, whereas the large intercrystalline porosity and microporosity are distributed below and above the unconformities due to the sea-level regression and transgression, respectively. It is concluded that production problems may occur in porous and permeable intercrystalline-porosity zones and the exploration of residual gas remains in the high porosity yet less permeable moldic-porosity zones.

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