--> Statistical Characterization of Non-Matrix Porosity and Permeability in a Devonian Dolostone Reservoir from Alberta Canada

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Statistical Characterization of Non-Matrix Porosity and Permeability in a Devonian Dolostone Reservoir from Alberta Canada

Abstract

Middle Devonian relative sea-level rise led to growth of fringing stromatoporoid reefs around Precambrian-granite inselbergs at the edges of the Peace River Arch in northern Alberta. Moldic pores are the only effective pores in these dolostones. Molds up to several cm diameter formed by leaching of fossil fragments. The matrix between the molds is microcrystalline dolomite; core analyses establish that the matrix has less than 0.1 mD permeability. Yet this currently-producing reservoir at Slave Field has yielded more than 57 million barrels of oil and water since 1981. Production comes from highly permeable layers where the moldic pores are touching one another. However, not all molds are touching, and core data show that dolostones with porosities over 10% can have permeabilities of less than 1 mD in zones where large open pores are not touching. Thus, there is not a statistically significant correlation between porosity and permeability. None the less, more than 440 porosity and permeability measurements from 8-cm diameter core cylinders can be organized to demonstrate facts of exploration and development significance. First, the cores are described by original depositional facies which include carbonate mudstone, skeletal-fragment grainstone, Amphipora rudstone-floatstone, and stromatoporoid boundstone. Second, the core data can be grouped into classes with touching vugs and non-touching vugs. Mudstone facies do not contain fossils and as a result, there is no possibility of finding vugs, while facies with fossils always contain vugs but some are touching, and some are not. The probability of encountering touching vugs increases as the number and size of fossil fragments increases in the cores. Although the pores are diagenetic in origin, the distribution of porosity and permeability can be modeled by mapping original depositional facies in the carbonate atolls. Then the data are plotted to show well-defined normal distributions of porosity and log-normal distributions of permeability within each facies type. The method of defining probability distributions for porosity and permeability by facies types can be used to constrain reservoir-volume and recovery-factor estimates for this type of carbonate reservoir. Analogs including this one can be referenced to show that porosity and permeability follow statistical distributions. Start with these ideas in mind when attempting to characterize a non-matrix carbonate reservoir.