Geochemical, petrographic and petrophysical characterization of the lower Bakken Shale, Divide County, North Dakota

Abstract The Lower Bakken Shale is a key member of the Bakken Petroleum System, which is a prolific unconventional accumulation in North America. Unconventional accumulations have unpredictable lateral variations in hydrocarbon production due to a variety of factors including porosity, permeability, and other rock properties. Therefore, understanding the geochemical (source rock potential), petrological, and petrophysical properties of these units is essential in evaluating the hydrocarbon potential for the Lower Bakken Shale. This study utilized cores from four wells within three fields in Divide County, North Dakota, with samples collected for Rock- Eval pyrolysis, organic petrology, petrographic thin section studies, XRD, SEM, porosity, pore size, and pore fluid distribution. Helium porosimetry and NMR T2 porosity techniques were used to estimate porosity and also to check the quality of the results and avoid discrepancies. Results showed that maturity in the study area varies from immature to early mature using Tmax and solid bitumen reflectance. Organic petrology showed the dominance of solid bitumen and marine alginites, which confirms the Type II kerogen identified from pyrolysis and marine depositional environment in the study area. Major organic matter types identified from SEM studies involve stringy OM, OM-mineral admixture, particulate OM and pure OM which host the majority of the organic matter pores. Furthermore, pore types identified from SEM include mineral matrix pores, organic matter pores, and microfracture pores. Porosity values based on both helium and NMR varies but the difference was nominal and attributed to the presence of abundant clay minerals. Pore sizes are distributed within micropores, mesopores, and macropores with thermal maturity, TOC, and clay mineral proportion having a major influence on pore distribution. Clay-bound water was identified to be the dominant fluid within the shale samples using the T2 cutoff values and supporting evidence from the abundance of clay matrix porosity.