EnergyBC

Stratigraphy

The Queen Charlotte Basin is termed a Tertiary Basin, as extension and deposition of the sediments occurred less than 65 Ma (million years ago), but in fact some of the more interesting (organic-rich source rocks) geologic units are older. The basic stratigraphic framework is shown in Figure 2 (from Dietrich, 1995).

The so-called basement of the basin, i.e., the floor unit for any expected petroleum formation and occurrence, is the several thousand meters of volcanics comprising the Triassic Karmutsen Formation (Ladinian-Carnian age, ca. 230 Ma, up to 4,600m thick).

Karmutsen strata are overlain by up to 1000m of Upper Triassic and Lower Jurassic limestones, sandstones and shales of the Kunga and Maude groups, and are thought to be one of the primary source rocks for petroleum generation .

Lower Mesozoic successions are overlain by several hundred meters of volcanic and volcaniclastic rocks of the Middle Jurassic Yakoun and Moresby groups.

Overlying these groups are up to 2500m of Upper Jurassic-Cretaceous sandstone-shale-conglomerate of the White Point Beds and Queen Charlotte Group. Selected intervals of the Queen Charlotte Group have good reservoir characteristics, the most promising being shallow-marine sandstones and granule conglomerates in the basal part of the formation. These strata were deposited along NW-SE paleoshorelines in the Queen Charlotte Islands and western parts of Dixon Entrance, Hecate Strait and the Queen Charlotte Sound (Haggart, 1991; Lyatsky and Haggart, 1993). Fogarassy and Barnes (1991) described outcrop reservoir characteristics with porosity averaging 5 to 10%, and permeability considered fair to good.

Neogene volcanic and sedimentary rocks of the Masset and Skonun formations overly Paleogene and older successions. The Skonun consists of interbedded sandstone, shale, conglomerate and coal, up to 6 km thickness offshore. This contains the primary petroleum exploration targets, with sandstone porosities between 25 to 35% (>2000m), and fair to very good permeability (10 to 1500md) (Dietrich, 1995). At depths of 2000-3000m porosity decreases by 5% with fair permeability (10 to 100md). Below 3000m, reservoir potential is minimal due to low permeability.

Some credit from above text to Appendix 6 of British Columbia Offshore Hydrocarbon Development: Report of the Scientific Review Panel prepared by Strong, David, Patricia Gallagher and Derek Muggeridge, January 2002.