Controls on reservoir quality of the Nanushuk Formation (Albian–Cenomanian), North Slope, Alaska

Abstract

Recent hydrocarbon discoveries in the Albian–Cenomanian Nanushuk Formation on the North Slope of Alaska have revived interest in exploration of the Colville basin. The Nanushuk forms a segment of the Brookian sequence and together with the genetically related Torok Formation comprises part of a giant clinothem filling the western two-thirds of the basin. It consists of a succession of intertonguing marine and nonmarine strata interpreted as marine shelf, deltaic, strandplain, and fluvial deposits. Deposition occurred in two deltaic complexes, one sourced from large drainage basins extending west of present-day Arctic Alaska, the other from smaller catchment areas with headwaters in the ancestral Brooks Range to the south.The Nanushuk Formation consists of medium- to very fine-grained lithic sandstone and siltstone comprised largely of monocrystalline and polycrystalline quartz, chert, and argillaceous sedimentary and metasedimentary rock fragments. With progressive burial and compaction, ductile deformation of the argillaceous detritus is the principal mechanism of porosity and permeability loss in the sandstone. Cements are a minor component and have minimal effect on diagenesis of the strata. Reservoir quality varies extensively across the North Slope and understanding the factors controlling reservoir potential is a critical aspect of recent exploration programs.Two groups of sandstone are recognized based on differences in reservoir quality: a low-porosity group with maximum porosity less than 20 percent, and a high-porosity group with higher porosity values for a given permeability and maximum porosity exceeding 30 percent. Variation in reservoir quality within each group is delimited by depositional texture which is a primary, local control. The disparity between the groups results from differences in the maximum burial depth (Dmax) the rocks experienced which is a secondary, regional control. Linear regression models for porosity–Dmax and permeability–Dmax relations enable forecasting the reservoir potential of sandstone and siltstone containing only minor cement.