Abstract Tertiary and Cretaceous nonmarine sandstones are reservoirs for large amounts of natural gas at Natural Buttes field in the eastern part of the Uinta basin, Utah. A cored interval in the Upper Cretaceous Tuscher Formation dominantly comprises fine- to medium-grained, moderately to well-sorted sandstones and less abundant carbonaceous and coaly shale beds. These rocks represent sedimentation on the lower part of an alluvial braidplain. The Paleocene and Eocene Wasatch Formation unconformably overlies Cretaceous rocks and intertongues with marginal lacustrine strata of the Green River Formation. The cored interval in the upper part of the Wasatch consists of fine-grained lenticular sandstones with small-scale cross-bedding, argillaceous siltstones, and variegated mudstones, all of which were deposited in lower delta plain settings along the margin of Lake Uinta. Cored sandstones in the Tuscher and Wasatch formations have been extensively modified by minor quartz overgrowths; by the precipitation and subsequent dissolution of a carbonate mineral assemblage comprising iron-free calcite, ferroan calcite, dolomite, and ankerite; by local occurrences of anhydrite and barite; and by the formation of authigenic illite, mixed- layer illite-smectite, kaolinite, chlorite, and corrensite. Most authigenic carbonate formed during early burial before significant compaction. During later stages of diagenesis, anhydrite and barite precipitated locally, replacing detrital grains and mineral cements such as carbonate. Porosity and permeability have been significantly reduced in the sandstones owing to clay mineral development and the formation of carbonate cement. Large amounts of natural gas are stratigraphically trapped in these lenticular, diagenetically modified low-permeability sandstones. Potential source rocks in the Tuscher Formation may have generated thermogenic gas even though they are only moderately mature with respect to liquid hydrocarbon generation.

Abstract Nine oils and 15 rock samples from across the National Petroleum Reserve in Alaska (NPRA) were analyzed by standard geochemical techniques in order to characterize the Alaskan North Slope oils and to attempt to determine the origin of these oils through direct crude oil-source rock correlation. Results of this study indicate four genetic oil types. One major oil type (Type I) includes the oils from Prudhoe Bay, South Barrow, and Fish Creek. These oils are reservoired in rocks of the Sadlerochit Group, pebble shale units and Sag River Sandstone, and Nanushuk Group, respectively (ranging in age from Permian to Cretaceous). Type I oils have the following geochemical characteristics: high sulfur content (0.9-1.8%), C19/C23 tricyclic terpane ratios 0.7 to 0.13, pristane/phytane ratios 1.3 to 1.5, farnesane/C^ isoprenoid ratios 0.9 to 1.0, and stable carbon isotope ratios for the saturated hydrocarbons from δ 13 C —28.4 to —29.4 and for the aromatic hydrocarbons between δ l3 C —28.7 and —29.3. The oils of Type I contain biomarkers that are similar in distribution to the extractable organic matter from the Kingak Shale and Shublik and Echooka formations rocks. However, a large (4-5 per mil) difference in stable carbon isotopes exists between the aromatic hydrocarbon fractions from the oils and the Kingak and Echooka rocks. This difference is too large to result from migration alone and suggests that the Kingak and Echooka rocks are not the major source of Type I oils regardless of some genetic similarities in organic matter. The best overall geochemical correlation exists between the oils of Type I and rocks of the Shublik. A second major North Slope oil type (Type II) includes oils from the Simpson and Umiat fields. The Simpson oils were encountered in shallow core tests and as a seep in a seismic-test hole. The Umiat oil is from Cretaceous reservoirs of the Nanushuk Group. The Simpson-Umiat Type II oils have the following geochemical characteristics: low sulfur <0.2%, C19/C23 tricyclic terpane ratios >1.2, pristane/phytane ratios 2.1 to 2.2, farnesane/Cl6 isoprenoid ratios 0.6 to 0.7, and 6 t5 C ratios for the saturated hydrocarbons between —28.1 and —28.7 and for the aromatic fraction between —26.7 and —27.7. These Type II oils have many geochemical characteristics similar to the extractable organic matter from the Torok Formation and the pebble shale unit. However, the poor source rock quality of the organic matter in the Torok suggests that these rocks are poor oil sources but may have generated some gas. A third genetic oil type (Type HI) is represented by the oil-show in the Dalton test well obtained from rocks of the Lisburne Group of Mississippian to Permian age. The Dalton oil is geochemically similar in many respects to Type I oils, but dissimilarities in sulfur, hydrocarbon, and asphaltic contents indicate probable genetic source differences. Geochemically, the Dalton oil resembles oils derived from carbonate rocks. Organic-rich carbonate units within the Lisburne are suspected as the source of the Dalton oil. A fourth oil type (Type IV) is represented by the condensate from the Seabee well reservoired in the Torok Formation of Cretaceous age. Geochemical comparison data on this sample are minimal (carbon isotopes only) because of its narrow boiling range. The carbon isotopes for the hydrocarbons from the Seabee condensate are most like carbon isotopes for hydrocarbons from the Torok and the pebble shale unit.