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 The reconstructed structural and thermal history of the Piceance Creek basin of western Colorado defines the geologic and geochemical conditions for the occurrence of gas in the Upper Cretaceous Mesaverde Group. In general the Mesaverde consists of two parts: a lower marginal marine section with mostly blanket reservoirs and an upper nonmarine part with mostly lenticular reservoirs. Most of the gas produced has been from reservoirs in the marginal marine section; however, because of its great thickness and abundance of gas shows, the nonmarine section is thought to contain more gas in place. Reservoirs in the nonmarine rocks usually have low permeability and are unconventional. Attempts to explain coal ranks using recent coal metamorphism models were unsuccessful, primarily because of the margin of uncertainty in present–day formation temperature readings in the basin. Coals around the basin margins were uplifted to their present high stratigraphic position in the basin during the final stages of the Laramide orogeny during the late Eocene and appear to be frozen at roughly pre–uplift coal ranks. The relatively high rank of some of these coals suggests that coal ranks throughout the basin attained close to their present–day rank from burial heating prior to the end of the Eocene. The effects of later thermal events on coal rank, such as Oligocene–age plutonism in the southern part of the basin, appear to have been minimal. If this is correct, then peak hydrocarbon generation in the basin peaked during the Eocene. Closed anticlines, which have produced much of the gas in the basin, appear to be Laramide growth structures; hence, peak gas generation occurred while the anticlines were growing.