Comparing Source Rock Maturity With Pore Size Distribution and Fluid Saturation in the Bakken-Three Forks Petroleum System of the Williston Basin

Abstract

With the continuous demand for fossil fuel and advancement in technology, the unconventional petroleum resources have come into limelight. The Devonian Three Forks formation consisting of carbonate and clastic sediments in the Williston basin is an unconventional reservoir with about 20 billion barrels of oil in place (North Dakota DMR 2010). However, understanding of rock properties and fluid saturation is still challenging within the different lithofacies.

The petroleum prospectivity was evaluated by integrating organic maturity and hydrocarbon generation with porosity distribution and fluid saturation in the Ambrose field and adjacent fields. The organic maturity was done by running a programmed pyrolysis analysis (Source Rock Analyser) at an interval of 1ft through the lower Bakken Shale that overlies the Three Forks Formation. Core samples from four (4) wells were utilized for this study. Physical core description and wireline logs were used to identify and correlate the facies within the Three Forks Formation of the study area. Five major lithofacies were identified. They are: 1) green – grey massive mudstone, 2) tan massive dolostone 3) grey – tan laminated mudstone and dolostone 4) tan - dark brown mottled dolostone and 5) Green – brown conglomerated mudstone.

Core samples from each lithofacie of interest in the wells were collected and prepared for NMR analysis by saturating with NaCl brine solution under 100 psi of compressed air for a minimum of 30 days. Porosity analysis was acquired from 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 (less than 0.5 microns), mesopores (0.5 to 5 microns), and macropores (greater than 5 microns).

Tmax from the programmed pyrolysis showed that the organic maturity between wells varies from 427°C to 439°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. The laminated lithofacies are expected to have a bimordal T2 relaxation time which is proportional to pore space divided between mud laminae and fine intercrystalline porosity while the massive mudstone lithofacie have the shortest T2 relaxation time consistent with clay bound microporosity.

AAPG Datapages/Search and Discovery Article #90323 ©2018 AAPG Annual Convention and Exhibition, Salt Lake City, Utah, May 20-23, 2018