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Micropore-dominated carbonate reservoirs remain challenging for accurate hydrocarbon evaluation and production because conventional reservoir models using depositional textures and petrophysical properties to distribute porosity and permeability cannot be applied. Nevertheless, understanding the distribution of pore systems and predicting the fluid flow behavior of microporous reservoirs is fundamental because micropores constitute a significant percentage of the total porosity and storage capacity. We present the results from an integrated study on the producing micropore-dominated Word field characterized by a facies-independent, diagenetically controlled pore system that approaches 100% microporosity. Four cored wells through the Albian Edwards Formation were described and correlated using stacking patterns and vertical facies trends; pore type characterization was done through thin section petrography, routine core analyses, scanning electron microscopy, and mercury injection capillary pressure data. This study is an example of a permeable reservoir in which intergrain pores are cemented during burial diagenesis and micropores, being more resistant to cementation, remain open to depths greater than 4000 m (13,000 ft). A unique relationship exists between porosity, permeability, median pore throat size, and microcrystalline textures, independent of facies and fabrics. Cumulative gas production data show there is a correlation between the total porosity and the structural position of the wells: wells high on the structure have the highest production. We demonstrate that an equally well–connected micropore network exists in mud-dominated rocks via the matrix and via grain-to-grain contacts in grain-dominated rocks. The here described intragrain micropore network through grain-to-grain contacts in cemented grainstones is a new carbonate flow path that will likely become more important as more unconventional carbonate reservoirs are explored.