Cretaceous carbonaceous rocks from the Norfolk Ridge system, Southwest Pacific: Implications for regional petroleum potential

Abstract

Late Cretaceous carbonaceous rocks have been dredged from two sites on the Norfolk Ridge system northwest of New Zealand. On the West Norfolk Ridge, Raukumara Series (late Cenomanian to late Coniacian, 95–86.5 Ma) coal measure sandstones and mudstones contain dispersed, immature #OPRO 0.37%), terrestrial (type III) organic matter and have poor petroleum generative potential (TOC 2.2–2.8%, S2 1.2–1.6 mg HC/g rock). However, the in situ coal measure sequence may contain abundant coal seams with excellent generative potential, and thus constitutes a potential source rock formation for the adjacent New Caledonia and Reinga Basins that have thick sections of sediments. The coal measures probably formed in a coastal plain environment subjected to episodic marine incursions. At the second dredge site, near the junction of the Norfolk and Reinga Ridges, a late Piripauan to early Haumurian (Santonian‐Campanian, 85–75 Ma) marine shale contains sparse, mixed marine and terrestrial (type II/III) organic matter. Hopane and sterane parameters imply a maturity equivalent to at least 0.6% Ro, but the analysed shale has poor generative potential (TOC 0.9%, S2 1.4 mg HC/g rock). Biomarkers suggest that the terrestrial contribution to bitumen in the shale is minor compared with the marine, but kinetic parameters are more consistent with a type III kerogen than the type II/III kerogen identified. A likely explanation of the discrepancy is that early oil generation has occurred in the sample, possibly associated with sulphur incorporated into the kerogen during diagenesis. In addition, a high saturated: aromatic hydrocarbon ratio suggests that mature bitumen may have migrated into the shale. Given greater TOC contents and sufficient volume, the shale could be a potential source rock within the Reinga Basin and Norfolk and Three Kings Ridges. A simple thermal model at a pseudo‐well site in the Reinga Basin shows that at depths >4.5 km below seabed, potential source rocks with the kerogen kinetic parameters of the dredged rocks should be generating hydrocarbons and approaching the threshold of oil expulsion. The model does not explain the presence of migrated hydrocarbons in the shale sample unless similar source rocks are more deeply buried nearby or thermal conditions were greater than those modelled. In comparison, a predominantly marine unit like the Waipawa Shale would be in the oil window at 3.0 km. Maturity levels may well have been enhanced by increased heat flow associated with the latest Oligocene to early Miocene rifting and opening of the adjacent Norfolk Basin. If equivalent rocks with sufficient organic richness exist in the Northland Basin (part of the Reinga Basin adjacent to New Zealand), where sediment thickness commonly exceeds 5 km and locally exceeds 7 km, they will have generated and expelled hydrocarbons.