Abstract The US Geological Survey recently assessed the potential for undiscovered conventional petroleum in the Arctic. Using a new map compilation of sedimentary elements, the area north of the Arctic Circle was subdivided into 70 assessment units, 48 of which were quantitatively assessed. The Circum-Arctic Resource Appraisal (CARA) was a geologically based, probabilistic study that relied mainly on burial history analysis and analogue modelling to estimate sizes and numbers of undiscovered oil and gas accumulations. The results of the CARA suggest the Arctic is gas-prone with an estimated 770–2990 trillion cubic feet of undiscovered conventional natural gas, most of which is in Russian territory. On an energy-equivalent basis, the quantity of natural gas is more than three times the quantity of oil and the largest undiscovered gas field is expected to be about 10 times the size of the largest undiscovered oil field. In addition to gas, the gas accumulations may contain an estimated 39 billion barrels of liquids. The South Kara Sea is the most prospective gas assessment unit, but giant gas fields containing more than 6 trillion cubic feet of recoverable gas are possible at a 50% chance in 10 assessment units. Sixty per cent of the estimated undiscovered oil resource is in just six assessment units, of which the Alaska Platform, with 31% of the resource, is the most prospective. Overall, the Arctic is estimated to contain between 44 and 157 billion barrels of recoverable oil. Billion barrel oil fields are possible at a 50% chance in seven assessment units. Undiscovered oil resources could be significant to the Arctic nations, but are probably not sufficient to shift the world oil balance away from the Middle East.

Abstract The Eurasia Basin petroleum province comprises the younger, eastern half of the Arctic Ocean, including the Cenozoic Eurasia Basin and the outboard part of the continental margin of northern Europe. For the USGS petroleum assessment (CARA), it was divided into four assessment units (AUs): the Lena Prodelta AU, consisting of the deep-marine part of the Lena Delta; the Nansen Basin Margin AU, comprising the passive margin sequence of the Eurasian plate; and the Amundsen Basin and Nansen Basin AUs which encompass the abyssal plains north and south of the Gakkel Ridge spreading centre, respectively. The primary petroleum system thought to be present is sourced in c . 50–44 Ma (Early to Middle Eocene) condensed pelagic deposits that could be widespread in the province. Mean estimates of undiscovered, technically recoverable petroleum resources include <1 billion barrels of oil (BBO) and about 1.4 trillion cubic feet (TCF) of nonassociated gas in Lena Prodelta AU, and <0.4 BBO and 3.4 TCF nonassociated gas in the Nansen Basin Margin AU. The Nansen Basin and Amundsen Basin AUs were not quantitatively assessed because they have less than 10% probability of containing at least one accumulation of 50 MMBOE (million barrels of oil equivalent).

Abstract The Lomonosov microcontinent is an elongated continental fragment that transects the Arctic Ocean between North America and Siberia via the North Pole. Although it lies beneath polar pack ice, the geological framework of the microcontinent is inferred from sparse seismic reflection data, a few cores, potential field data and the geology of its conjugate margin in the Barents–Kara Shelf. Petroleum systems inferred to be potentially active are comparable to those sourced by condensed Triassic and Jurassic marine shale of the Barents Platform and by condensed Jurassic and (or) Cretaceous shale probably present in the adjacent Amerasia Basin. Cenozoic deposits are known to contain rich petroleum source rocks but are too thermally immature to have generated petroleum. For the 2008 USGS Circum Arctic Resource Appraisal (CARA), the microcontinent was divided into shelf and slope assessment units (AUs) at the tectonic hinge line along the Amerasia Basin margin. A low to moderate probability of accumulation in the slope AU yielded fully risked mean estimates of 123 MMBO oil and 740 BCF gas. For the shelf AU, no quantitative assessment was made because the probability of petroleum accumulations of the 50 MMBOE minimum size was estimated to be less than 10% owing to rift-related uplift, erosion and faulting.

Abstract The Ordovician St. Peter Sandstone in the Illinois Basin has undergone complex diagenelic modification involving (1) early K-feldspar, dolomicrospar, and illite precipitation, (2) late quartz, planar and baroque dolospar, anhydrite, calcite, and illite cementation and (3) carbonate-cement and K-feldspar dissolution. In southern Illinois, burial reconstruction in combination with silicate mineral age dates indicate that late-diagenetic cementation in the St. Peter Sandstone occurred during deep burial (˜3,300 m) in Late Pennsylvanian and Early Permian time when major ore-forming (MVT) events were taking place in the region. Maturation kinetics suggest that precipitation temperatures at this depth were ˜140°C, assuming the major heat source was from the basement. The range of burial temperatures predicted for the St. Peter Sandstone (˜65°–140°C) compares closely with the temperatures of hydrothermal ore-forming fluids (˜80°–18O°C) suggesting the fluids involved in diagenesis (i.e., dolomitization and quartz and anhydrite precipitation) may have been part of the same (paleo)hydrologic system that caused MVT mineralization. In the shallow northern part of the basin, fluid inclusion data indicate ihat dolospar precipitated at higher temperatures (110°–115°C) than would be expected in these otherwise low temperature (<50°C) rocks. Provided these values are reliable, the St. Peter Sandstone was affected by a heat source that was not burial related. Hydrothermal fluids associated with the Upper Mississippi Valley District could account for these temperatures. Fluid inclusion and isotopic data indicate that the fluids involved in burial cementation throughout the basin were saline and comparable in composition to the brines responsible for MVT mineralization (˜20 wt% NaCl equivalent). In the absence of igneous activity, warm, topographically driven fluids (i.e., low temperature (<200°C) brines) moving updip from the southern tectonic margin of the basin can explain much of the dolospar and the associated mineral cements in the St. Peter Sandstone. 18 O-depleted dolospar concentrated along the La Salle anticline in east-central Illinois suggest that this structural feature was a major conduit for the movement of these hot fluids through the basin. The ultimate source of the fluids may have been the Ouachita fold belt or the Reelfoot rift. There also is some evidence Ihat fluids were expelled from the Arkoma and Black Warrior Basins.

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 Gas production in the lower Tertiary Wasatch Formation and Upper Cretaceous Mesaverde Group in the Piceance basin, Colorado, is controlled principally by a network of open and partly mineralized natural fractures. The Piceance Creek field, situated on the Piceance Creek anticline, and the Rulison and Divide Creek fields all have extensive fractures. These fractures formed in response to high pore-fluid pressures that developed during hydrocarbon generation and to widespread tectonic stress associated with periods of uplift and erosion that occurred during the late Tertiary. Sandstone beds commonly contain vertical extension fractures that are cemented with fine- to coarse-crystalline calcite and locally with quartz, barite, and dickite. These fracture-fill minerals cut detrital grains, and authigenic mineral cements indicating that fracture development and mineralization occurred during the later stages of diagenesis. The δ I3 C compositions for calcite vary over a wide range (from — 5.0 to — 11.6‰ for the Wasatch and from — 0.7 to — 10.4‰ for the Mesaverde) and may reflect the original isotopic composition of matrix carbonate that was present in nearby sandstone beds. δ I8 O values for fracture-fill calcite generally are light, ranging from — 9.5 to — 14.9‰ for the Wasatch and from — 13.3 to — 17.7‰ for the Mesaverde. Most gas encountered in Tertiary and Cretaceous rocks was generated in situ from interbedded carbonaceous and coaly shales and tongues of organic-rich lacustrine rock. In areas that are extensively fractured, gas may comprise a mixture from different sources due to migration along open faults and fractures.