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Maturity and Organofacies Assessment of Bakken Shale: Implications for New Areas for Exploration and Production

Daniel M. Jarvie1 and Michael S. Johnson2
1Worldwide Geochemistry, LLC, Humble, TX
2Consultant, Denver, CO

Williston Basin Bakken oil fields are unconventional stratigraphic traps that require horizontal drilling. The upper and lower members of the Bakken are excellent source beds and consist of highly organic rich black shales with TOC values averaging between 11 and 12%. The middle member is a clastic-carbonate unit with a preferred dolomitic facies. All three members contribute to the reservoir character with fracturing being the dominant porosity type. Fracturing is caused by overpressuring with contribution from lithostatic pressure, nonhydrocarbon and hydrocarbon generation from the black shales in mature areas, episodic basement uplift and wrench faulting, and Prairie Salt dissolution.

Generally, where productive, lineaments define dominantly northeast and northwest-trending fault systems and other structural features. Together with thickness variations, stratigraphic changes and overpressuring (up to 0.7 psi/ft.), Bakken reservoirs have been created. Two recent major oil discoveries, Elm Coulee and Parshall fields, have caused a renewal of the cyclic exploration effort of the Bakken.

These recent discoveries in the Williston Basin have occurred in areas where the Bakken Shale is immature to earliest oil window thermal maturity. Although controversial nearby indigenous oil is apparently being produced from the organic matter rather than migration into the system from more mature down-dip source areas. This assessment is based on geochemical characteristics of Parshall Field oil, which based on light hydrocarbon distributions is a low thermal maturity oil similar to the overlying Bakken Shale. Bakken Shale samples from Parshall Field area have geochemical characteristics suggesting potential production prior to renewed drilling and discoveries in this area.

Bulk open-system kinetic data measured on several Bakken Shale samples is used to evaluate relative rates of oil generation. While source rocks have been identified that generate hydrocarbons at lower thermal thresholds than classical onset of hydrocarbon generation windows, these are usually high sulfur Type II-S kerogens such as the Monterey Formation, rather than low sulfur, marine shales such as the Bakken. Our experience, however, is that all kinetic models currently in use, tend to under predict early hydrocarbon generation. A revised assessment of these results provides some insights as to why this may occur.

Investigation of available Bakken Shale and middle member rock data suggest variations in organofacies that are now being evaluated and compared. There is considerable variation in their properties and these may play a role in variations in the timing of hydrocarbon generation across the basin. Fracturing results from a variety of factors, but our investigation focuses on generation-induced fractures. This could result from either nonhydrocarbon or hydrocarbon generation. Likewise, bulk kinetic data suggests a range of temperatures for the onset of generation apparently controlled by organofacies differences in Bakken Shale with one organofacies generating at lower temperatures than the predominant organofacies found in the Bakken. Thus, apart from other geological activity, both hydrocarbon and nonhydrocarbon gases generated at low thermal maturities may provide means for creating fractures or secondary porosity for early oil accommodations.

A key issue that arises from this investigation is the possibility of identifying additional Bakken and shale-oil plays in other basins that have been described as too low thermal maturity for indigenous hydrocarbon generation.

AAPG Search and Discovery Article #90092©2009 AAPG Rocky Mountain Section, July 9-11, 2008, Denver, Colorado