Vito F. Nuccio

Source of Anomalous Magnetization in Area of Hydrocarbon Potential: Petrologic Evidence from Jurassic Preuss Sandstone, Wyoming-Idaho Thrust Belt

The Jurassic Preuss Sandstone, which crops out in the central part of the Wyoming-Idaho thrust belt on trend with a hydrocarbon-producing region to the south, has been previously identified as the source of anomalous magnetization in the area. Elsewhere, anomalous magnetization in sedimentary rocks near hydrocarbon accumulations has been attributed to hydrocarbon-engendered magnetic minerals, but magnetization of the Preuss is controlled by detrital magnetite. Evidence of a detrital origin for magnetite includes (1) concentration of magnetite grains along laminations containing other heavy minerals, (2) the presence of exsolved ilmenite, hematite, and spinel in the magnetite grains, and (3) titanium contents typical of igneous-derived magnetite. That detrital magnetite is responsible for the anomalous magnetization in the Preuss is further indicated by the systematic eastward decrease in magnetite abundance corresponding to a similar eastward decrease in magnetic susceptibility and remanent magnetization of the unit. Petrologic and vitrinite reflectance studies indicate a complex low-temperature (<150°C or 302°F) diagenetic history for the Preuss. Nevertheless, preservation of detrital magnetite, the presence of diagenetically early ferric oxide minerals, and the absence of sulfide minerals all indicate that the Preuss has not experienced sulfidic-reducing conditions common in areas of hydrocarbon seepage. The marine carbon isotopic composition of calcite that cements most Preuss sandstones (^dgr13C values ranging from -2.47 to 1.48^pmil is evidence that carbonate diagenesis also was not influenced by hydrocarbons. The results of this multidisciplinary study of the Preuss underscore the importance of similar studies when evaluating the sources of aeromagnetic anomalies in areas of hydrocarbon potential.

Upper Cretaceous Shannon Sandstone reservoirs, Powder River basin, Wyoming; evidence for organic acid diagenesis?

Comparison of the petrology of shallow and deep oil reservoirs in the Upper Cretaceous Shannon Sandstone Beds of the Steele Member of the Cody Shale strongly suggests that organic acids have had a more significant impact on the diagenetic alteration of aluminosilicate grains and carbonate cements in the deep reservoirs than in the shallow reservoirs. Vitrinite reflectance and Rock-Eval measurements, as well as the time-temperature index and kinetic modeling, indicate that deep reservoirs have been subjected to maximum temperatures of approximately 110-120 degrees C, whereas shallow reservoirs have reached only 75 degrees C. Only the deep reservoirs, therefore, have reached higher temperatures and have been (and some still are) within the zone (80-120 degrees C) of maximum organic acid production. Burial history reconstruction and paragenetic relations show that oil migration into Shannon reservoirs occurred in the middle to late Tertiary. In shallow reservoirs, detrital grains exhibit minor dissolution, sparse and small overgrowths, and secondary porosity created by dissolution of early calcite cement. However, deeper sandstones are characterized by extensive dissolution of detrital K-feldspar and detrital glauconite grains, and precipitation of abundant, large quartz and feldspar overgrowths. Quartz overgrowths commonly have crystallographically controlled etch pits. Throughout the Shannon and Steele, dissolution of glauconite and degradation of kerogen were probably aided by clay mineral/organic catalysis, which caused simultaneous reduction of iron and oxidation of kerogen. This process resulted in release of ferrous iron and organic acids and was promoted in the deep reservoirs by higher formation temperatures acco nting for more extensive dissolution of aluminosilicate grains. At the temperatures of deep Shannon reservoirs, alkalinity was buffered by organic acid anions so that iron released from glauconite precipitated as chlorite and abundant, multistage ferroan carbonate overgrowths. Carbonic acid produced from the dissolution of early calcite cement, decarboxylation of organic matter, and influx of meteoric water after Laramide uplift produced additional dissolution of cements and grains. Dissolution by organic acids and complexing by organic acid anions, however, best explain the intensity of diagenesis and absence of dissolution products in secondary pores and on etched surfaces of framework grains in deep reservoirs.

Comparison Between Immature Vitrinite and Solid Bitumen, Green River Formation, Piceance Creek Basin, Colorado: ABSTRACT

A major problem in organic petrography is the inability to distinguish immature vitrinite from solid bitumen. For this study, several samples of coal and solid bitumen, found interlayered with oil shales of the Green River Formation, were collected from three continuous cores. Each sample was analyzed under oil immersion with reflected light, with fluorescence (blue light), and by Rock-Eval. In the uppermost part of the cores, the vitrinite and solid bitumen have identical reflectance values under oil immersion (Ro), and the structureless (nonbanded, noncellular) vitrinite is optically indistinguishable from the bitumen. Observation with blue light reveals some details in both the vitrinite and the bitumen; solid bitumen appears more granular than the vitrinite. With the yellow filter, vitrinite shows some banding and spores are visible. Without the filter, the bitumen has an orange-brown hue, whereas the vitrinite is a bright blue. Rock-Eval analysis indicated a much higher hydrogen index for the bitumen (800-850) than for the coal (400-450). The total organic carbon (TOC) was higher for the coal (50-55) than for the bitumen (20-25). In the cores examined, the vitrinite reflectance changes downhole from 0.20 to 0.55; however, the Ro for the bitumen remains constant. Because reflectance values for vitrinite and solid bitumen can be the same or very similar, a researcher should not rely on reflectance values alone to distinguish vitrinite from solid bitumen. End_of_Article - Last_Page 293------------

Thermal Maturity of Organic Matter in Green River Formation, Piceance Creek Basin, Colorado: ABSTRACT

The thermal maturity of organic matter in the Green River Formation in the Piceance Creek basin was determined by vitrinite reflectance on coalified logs in the otherwise alginite-rich oil shale, marlstone, and sandstone. Only vitrinite from logs in sandstone and marlstone was used to determine thermal maturity because reflectance of vitrinite from alginite-rich oil shale generally is lower than that in associated other rock types. Mean random vitrinite reflectance (Ro) at the top of the Green River Formation ranges from about 0.30% around the perimeter of the basin, where maximum burial depth of the rocks was less than 1,000 m (3,300 ft), to 0.55% in the structurally lowest part of the basin, where maximum burial depth of the upper part of the Green River was ore than 1,500 m (4,900 ft). The Green River Formation is almost 1,200 m (3,900 ft) thick in the structurally lowest part of the basin, suggesting that the lower part of the formation in this area may have reached an Ro of 0.7%, generally accepted as the threshold for oil generation in alginitic rocks. Bitumin-filled fractures observed in core from this area of the basin support this conclusion. A lithologically similar lacustrine section of the Green River Formation in the adjacent Uinta basin, where maximum burial was as great as 5,600 m (18,400 ft), is producing large quantities of oil from overpressured, fracture-controlled reservoirs. Present-day maximum temperatures in the Green River Formation in the Piceance Creek basin are between 55 and 70°C (131 and 158°F) This temperature seems too low End_Page 492------------------------------ for hydrocarbon generation. However, temperatures in the past probably were high enough for hydrocarbon generation. Oil generated during this earlier, hotter period could have migrated into conventional stratigraphic and structural traps. End_of_Article - Last_Page 493------------

BASIN-CENTERED GAS SYSTEMS OF THE U.S.

The USGS is re-evaluating the resource potential of basin-centered gas accumulations in the U.S. because of changing perceptions of the geology of these accumulations, and the availability of new data since the USGS 1995 National Assessment of United States oil and gas resources (Gautier et al., 1996). To attain these objectives, this project used knowledge of basin-centered gas systems and procedures such as stratigraphic analysis, organic geochemistry, modeling of basin thermal dynamics, reservoir characterization, and pressure analysis. This project proceeded in two phases which had the following objectives: Phase I (4/1998 through 5/1999): Identify and describe the geologic and geographic distribution of potential basin-centered gas systems, and Phase II (6/1999 through 11/2000): For selected systems, estimate the location of those basin-centered gas resources that are likely to be produced over the next 30 years. In Phase I, we characterize thirty-three (33) potential basin-centered gas systems (or accumulations) based on information published in the literature or acquired from internal computerized well and reservoir data files. These newly defined potential accumulations vary from low to high risk and may or may not survive the rigorous geologic scrutiny leading towards full assessment by the USGS. For logistical reasons, not all basins received the level of detail desired or required.

Structural and Thermal History of Piceance Creek Basin, Colorado, in Relationship to Hydrocarbon Occurrence in Mesaverde Group: ABSTRACT

The purpose of this study was to reconstruct the structural and thermal history of the Piceance Creek basin to try to predict the occurrences of hydrocarbons in the Upper Cretaceous Mesaverde Group. A vitrinite reflectance map of basin-wide coal zone and several coal rank cross sections using vitrinite data was constructed. Isopach maps were used to reconstruct the burial history. In general, the Mesaverde Group can be divided into two parts: a lower mixed marine and nonmarine part, and an upper, largely nonmarine section. Vitrinite reflectance values range from Ro .50 to Ro 2.1, and indicate that both the nonmarine and marine Mesaverde are within the range of thermal gas generation throughout the basin, with the possible exception of the upper part f the nonmarine Mesaverde along the extreme west and End_Page 490------------------------------ southwest margins of the basin. The occurrence of gas correlates reasonably well with this finding. Both the marine and nonmarine Mesaverde are within the window of oil generation for most of the basin, except in the deeper parts where the upper limit of oil stability has been exceeded. Oil, however, is seldom encountered in the basin, probably because of a lack of abundant source beds with oil-generating capabilities. The vitrinite values are much too high to have formed under the present geothermal gradient, which averages about 1.7°F/100 ft (3°C/100 m), and appear to reflect a paleothermal gradient of between 2.2 and 3.5°F/100 ft (4 and 6.3°C/100 m), with the highest gradients in the southern part of the basin. It is suggested that this high gradient occurred during Oligocene time when the southeastern part of the basin was extensively intruded by magmas of intermediate composition. Overpressuring has thus far only locally been encountered in the basin. The lack of a well-defined overpressured area may be a combination of: (1) a decrease in the geothermal gradient since Oligocene time, and (2) uplift and removal of overburden during the last 10 million years. As much as 5,000 ft (1,500 m) of overburden has been removed in some parts of the Colorado River drainage. End_of_Article - Last_Page 491------------