How sandstone porosity and permeability vary with diagenetic minerals in the Scotian Basin, offshore eastern Canada: Implications for reservoir quality

- SEM-BSE image analysis for modal composition is a robust, low-cost method.
- Diagenetic minerals above 4% have a noticeable effect on permeability.
- There is no systematic regional variation in permeability but decreases with depth.
- Local factors play a great role to control reservoir quality in the Scotian Basin.
- Local factors include lithofacies, stratigraphy, pathways and overpressure.

The Scotian Basin is an under-explored offshore basin that has produced gas and minor oil from Jurassic-Cretaceous deltaic sandstones. Reservoir quality is an important exploration risk in the basin. This study evaluates whether there are systematic stratigraphic or geographic variations in diagenetic mineral assemblage control of reservoir porosity and permeability. Three data sets are used: a compilation of all available core-plug porosity and permeability measurements (3271 in total), a subset of 577 corresponding to thin sections with lithofacies assignments, and a subset of 35 thin sections principally from reservoir sandstones, in which modal abundance of diagenetic minerals has been determined by image analysis of scanning electron microscope backscattered electron images. Abundances above a 4% threshold of diagenetic kaolinite, calcite and ankerite correlate inversely with permeability, but chlorite and possibly siderite correlate positively. Diagenetic assemblages show no systematic variation with stratigraphy or geography, both of which may involve variable detrital supply. Permeability shows the well-known variation with grain size and depth of burial, but after correcting for these effects it is greatest in estuarine channel and river-mouth turbidite sandstones. This is because these facies preferentially develop chlorite rims on detrital quartz grains and are also the sites of enhanced flow of late basinal fluids resulting in secondary porosity. Local effects such as facies distribution, architecture of channel sandstones, fluid pathways related to complex salt tectonics, and the effects of overpressure are more important than predictable basin-wide effects in controlling sandstone reservoir quality.