Laura N.R. Roberts

Timing and petroleum sources for the Lower Cretaceous Mannville Group oil sands of northern Alberta based on 4-D modeling

The Lower Cretaceous Mannville Group oil sands of northern Alberta have an estimated 270.3 billion m3 (BCM) (1700 billion bbl) of in-place heavy oil and tar. Our study area includes oil sand accumulations and downdip areas that partially extend into the deformation zone in western Alberta. The oil sands are composed of highly biodegraded oil and tar, collectively referred to as bitumen, whose source remains controversial. This is addressed in our study with a four-dimensional (4-D) petroleum system model. The modeled primary trap for generated and migrated oil is subtle structures. A probable seal for the oil sands was a gradual updip removal of the lighter hydrocarbon fractions as migrated oil was progressively biodegraded. This is hypothetical because the modeling software did not include seals resulting from the biodegradation of oil. Although the 4-D model shows that source rocks ranging from the Devonian–Mississippian Exshaw Formation to the Lower Cretaceous Mannville Group coals and Ostracode-zone-contributed oil to Mannville Group reservoirs, source rocks in the Jurassic Fernie Group (Gordondale Member and Poker Chip A shale) were the initial and major contributors. Kinetics associated with the type IIS kerogen in Fernie Group source rocks resulted in the early generation and expulsion of oil, as early as 85 Ma and prior to the generation from the type II kerogen of deeper and older source rocks. The modeled 50% peak transformation to oil was reached about 75 Ma for the Gordondale Member and Poker Chip A shale near the west margin of the study area, and prior to onset about 65 Ma from other source rocks. This early petroleum generation from the Fernie Group source rocks resulted in large volumes of generated oil, and prior to the Laramide uplift and onset of erosion (58 Ma), which curtailed oil generation from all source rocks. Oil generation from all source rocks ended by 40 Ma. Although the modeled study area did not include possible western contributions of generated oil to the oil sands, the amount generated by the Jurassic source rocks within the study area was 475 BCM (2990 billion bbl).

Peat accumulation in coastal-plain mires: a model for coals of the Fruitland Formation (Upper Cretaceous) of southern Colorado, USA

Abstract In the northwestern part of the San Juan basin, Colorado, thick high-volatile B bituminous coal deposits in the Upper Cretaceous Fruitland Formation are associated with nearshore marine sandstones of the Pictured Cliffs Sandstone. Detailed work along the outcrop and examination of drill cores, revealed two coal-bearing zones in the lower 60 m of the Fruitland Formation. Each zone is up to 13 m thick and consists of interbedded bright and dull coal (average ash values of 17 and 34% on a moisture-free basis, respectively), thin fine-grained clastic partings and abundant altered volcanic ash partings. Isopachs of the interval between the top of the Pictured Cliffs Sandstone and a marker bed (Huerfanito Bentonite Bed) in the underlying Lewis Shale show linear zones where the interval abruptly thickens. These zones, which trend northwest to southeast, represent areas where the shoreline paused during an overall migration to the northeast. Isopach maps of coal in the lower part of the Fruitland Formation and subsurface correlation of shoreface sandstones with coal zones show that the thickest accumulation of coal is 20–25 km landward of these coeval shorelines. The Fruitland coals may be compared to the high-ash peats of the Dismal Swamp in the southeastern U.S.A., which form in pocosin mires about 20 km inland from the Atlantic coast. Clastic deposirion, resulting from coastal processes, precludes the formation of peat in low-lying mires adjacent to the shoreline. The high ash yield, numerous partings and the relationship with the coeval shoreline suggest that the coals in the lower part of the Fruitland Formation accumulated in mires that were transitional from low-lying to raised.

Geologic Model for the Assessment of Technically Recoverable Oil in the Devonian–Mississippian Bakken Formation, Williston Basin

The Upper Devonian and Lower Mississippian Bakken Formation in the United States part of the Williston Basin is a giant continuous (unconventional) oil resource. A recent U.S. Geological Survey (USGS) assessment estimated a mean volume of undiscovered technically recoverable oil for the Bakken Formation of about 3.65 billion bbl of oil. The estimate is based on a geologic model and a methodology that defines different assessment units by accumulation type (conventional or continuous), structural control, fracture occurrence and prediction, lithology and petrophysical properties, formation thickness, underlying salt movement or dissolution, and level of thermal maturity and oil-generation capacity of Bakken source rocks. The Bakken Formation consists of three informal members: (1) lower shale member; (2) middle sandstone member; and (3) upper shale member. Shale members are rich in marine organic matter (as much as 35% by weight) and are the petroleum source rocks, whereas the middle sandstone member varies in depositional facies and lithology and locally exhibits good matrix porosity (as much as 14%) but with low permeability, a characteristic of tight reservoirs. Additional commingled production occurs locally from matrix porosity in the immediately underlying, informally named, Sanish sand unit of the Upper Devonian Three Forks Formation. Combined, the Bakken Formation and Sanish sand define the Bakken composite continuous reservoir. On a larger scale, thermally mature organic-rich Bakken shale members are also the source for oils produced from locally occurring Waulsortian mounds or porous strata immediately above the upper shale member in the overlying Lower Mississippian Lodgepole Limestone. As a whole, elements of petroleum source, reservoir, seal, migration, and trap define the stratigraphic and geographic character of a Bakken-Lodgepole Total Petroleum System. The geographic extent of the continuous oil accumulation within the United States part of the Bakken Formation is defined as the area in which organic-rich shale members of the Bakken Formation are thermally mature with respect to oil generation. The area of the oil-generation window for the Bakken Formation continuous reservoir was determined using a combination of the following: (1) contour mapping of both the hydrogen index (HI) and log-resistivity well data of the upper shale member, (2) calibration of HI to the transformation ratio (TR) from one-dimensional burial history models, and (3) calibration of HI to total organic content. The geologic model used to further define continuous assessment units (AUs) within the Bakken Formation continuous oil accumulation was, in general, based on assumed levels of thermal maturity and generation capacity of the Bakken shale members as determined from HI and TR, relation of HI and TR to potential fracturing and structural complexity of the Williston Basin, and lithofacies distribution and petrophysical character of the middle sandstone member. The area of the oil-generation window was divided into five continuous AUs: (1) Elm Coulee-Billings Nose AU, (2) Central Basin-Poplar Dome AU, (3) Nesson-Little Knife Structural AU, (4) Eastern Expulsion Threshold AU, and (5) Northwest Expulsion Threshold AU. One hypothetical conventional AU, a Middle Sandstone Member AU, was defined external to the area of oil generation. Using the established U.S. Geological Survey methodology, assessment of each Bakken continuous AU was performed after estimation of effective well drainage areas, estimated ultimate recovery (EUR) from productive wells, and production success defined by a minimum EUR of 2000 bbl of oil. The AUs with the greatest resource potential are the Eastern Expulsion Threshold AU (mean volume, 0.973 billion bbl of oil), which is best represented by the Parshall and Sanish fields of Mountrail County, North Dakota, and the Nesson-Little Knife Structural AU (mean volume, 0.908 billion bbl of oil), where structural reservoir development exists, the middle sandstone member is thick and porous, the underlying Sanish sand reservoir unit is commonly present, and shale members have high oil-generation potential and the probability of abundant natural fracturing.