COMPARING SOURCE ROCK MATURITY WITH PORE SIZE DISTRIBUTION AND FLUID SATURATION IN THE BAKKEN-THREE FORKS PETROLEUM SYSTEM OF THE DIVIDE COUNTY,WILLISTON BASIN, NORTH DAKOTA

With increasing demand for fossil fuels and advancement in drilling technology, unconventional reservoirs continue to be attractive. The Devonian Three Forks Formation, a mixed carbonate and clastic system is an unconventional oil accumulation containing approximately 3.73 billion barrels of technically recoverable oil (Gaswirth and Marra, 2015). Therefore, understanding rock properties for the various lithofacies of the Three Forks relative to fluid saturation is critical for increasing recovery from the unconventional reservoir.

Petroleum potential of the system was evaluated by integrating organic maturity and hydrocarbon generation with porosity distribution and fluid saturation in the Ambrose and adjacent fields. The organic maturity was conducted with a programmed pyrolysis analysis (Source Rock Analyzer) using samples taken at one ft intervals through the Lower Bakken Shale. Core samples from four (4) wells were utilized for this study. Physical core description and wireline logs were used to identify and correlate the reservoir lithofacies within the Three Forks Formation.

Lithofacies were prepared for NMR (nuclear magnetic resonance) analysis by saturating with 300,000 ppm NaCl brine solution at 100 psi of compressed air for 40 days. Porosity analysis was conducted using a helium porosimeter and confirmed by NMR transverse relaxation (T2) analysis with Oxford Instruments GeoSpec2 core analyzer coupled with Green Imaging Technology software. Pore size distributions were calculated using T2 cutoff values to partition total porosity measurements into micropores, mesopores and macropores.

Tmax from the programmed pyrolysis indicate that organic maturity between wells varies from immature to mature (427°C to 440°C). NMR relaxation time results showed saturation is proportional to distribution of pore size with mesopore and macropore contributing more to oil saturation while, micropore contributes to water saturation. Laminated lithofacies have a bimodal T2 relaxation time which is proportional to pore space divided between micropores in mud laminae.