This paper clarifies the controls of oil retention in the Niobrara Formation, Denver Basin, in the western United States. Sweet spots have been recognized using a total of 98 core samples from 5 wells with maturities covering the oil window.
Oil retention in the source rock samples (carbonate content <70 wt. %) is controlled by organic matter richness and thermal maturity. In general, the vaporizable hydrocarbon (HC) yield at nominal temperatures at 300°C ([S1]; Rock-Eval) is positively correlated to total organic carbon (TOC). With increasing maturity, the so-called oil saturation index (S1/TOC × 100) first increases until a maximum retention capacity (100 mg HC/g TOC) is exceeded at the temperature at the maximum rate of petroleum generation by Rock-Eval pyrolysis (Tmax) of approximately 445°C and subsequently decreases. The depletion in oil retention capacity is believed to be associated with the appearance of organic nanopores.
Oil retention in samples with distinct reservoir potential (carbonate >30 wt. %) is controlled by carbonate content, which is positively related to the amount of retained oil. Petrographic features indicate that oil or bitumen is stored in porous calcite fossils (i.e., coccolith and foraminifera), which provide additional space for petroleum storage. Chalk samples (carbonate >85 wt. %) are characterized by anomalously low Tmax values caused by the influence of heavy petroleum or bitumen. The amount of this bitumen is higher than the initial petroleum potential of kerogen in A and B chalks and thus must have been emplaced here. The most likely sources are juxtaposed organic-rich marl layers.
Thus, sweet spots occur where carbonate content is either low (high TOC) or high (low TOC), whereas production of petroleum from the pore space of presumably brittle chalk seems more attractive than production from organic- and clay-rich rocks.