Abstract The Green River(!) petroleum system, located in northeast Utah in the Uinta Basin, is responsible for almost 500 million bbl of recoverable high pour-point and paraffinic oil, 12-13 billion bbl of inferred Tertiary and Cretaceous tar sandstone accumulations. It is a prolific complex of rocks that includes gilsonite, oil shales, and lacustrine source rocks in the Paleocene-Eocene Green River Formation. These source rocks include an open lacustrine facies containing mainly type I kerogen, a marginal lacustrine facies with types I, II, and III kerogens, and an alluvial facies with mostly type III kerogen. Some type I kerogens have TOC contents as high as 60 wt. % and average ∼6.0 wt. %. These kerogenous carbonate beds (oil shale) have hydrogen indices greater than 500 mg HC/g TOC. Oil is produced primarily from lenticular reservoirs that are parts of larger regional hydrocarbon accumulations, some of which span major structural elements. Regionally, alluvial rocks strati- graphically trap most oil in down-dip open and marginal lacustrine reservoirs. The exposed bitumen-bearing sandstones (tar sands) represent the surface expression of migrated oil in marginal lacustrine strata that are continuous with the downdip oil fields. Economically viable oil is recovered from the subsurface where the oil is above pour-point temperatures and is moveable and where strata are especially porous and permeable. However, oil-bearing reservoir rocks commonly extend beyond field limits. In the deep subsurface, wells are completed in overpressured strata where pods of open fractures provide high formation permeability sufficient to drain “tight” oil reservoirs. High fluid pressure gradients associated with these pods occur where impermeable rocks with abundant type I kerogen have been subjected to temperatures sufficient to generate hydrocarbons at a rate greater than the rate of fluid migration.

Abstract Stratigraphic, lithologic, and geochemical data provide ample evidence that carbonate rocks and not shales are the source beds of commercial oil in carbonate grainstone reservoirs of the Lower Cretaceous Sunniland Limestone of the South Florida basin. Detailed crude-oil-source-rock correlations, including gaschromatographic–mass-spectrometric analyses of steranes, and of tricyclic and pentacyclic terpanes, indicate that the algal-sapropelic, organic-rich argillaceous limestones in the lower Sunniland Limestone, particularly the down-dip, basinal facies, are the probable major source of upper Sunniland Conventional geochemical maturity parameters, plus biomarker isomerization ratios, indicate that the Sunniland oils and source rocks are marginally mature. The sterane ratios, commonly in conjunction with the extended hopane isomerization ratios, proved invaluable in deciphering the thermal maturity of carbonate rocks in south Florida and in pinpointing the upper threshold of the conventional oil-generation zone.