ABSTRACT The Williston Basin Bakken petroleum system is a giant continuous accumulation. The petroleum system is characterized by low-porosity and -permeability reservoirs, organic-rich source rocks, and regional hydrocarbon charge. Total Bakken and Three Forks production to December 2014 was 1.289 billion barrels (bbl) of oil and 1.3 trillion cubic feet of gas (TCFG) from 12,051 wells. U. S. Geological Survey (USGS) ( Gaswirth et al., 2013 ) mean technologically recoverable resource estimates for the Bakken petroleum system are 7.375 billion barrels of oil, 6.7 tcf of gas, and 527 million barrels of natural gas liquids. The Bakken Formation regionally in the Williston Basin consists of four members: upper and lower organic-rich black shale, a middle member (silty dolostone or limestone to sandstone lithology), and a basal member recently named the Pronghorn. The Bakken Formation ranges in thickness from a wedge edge to over 140 ft (43 m) with the thickest area in the Bakken located in northwest North Dakota, east of the Nesson anticline. The Three Forks is a silty dolostone throughout much of its stratigraphic interval. The Three Forks ranges in thickness from less than 25 ft (8 m) to over 250 ft (76 m) in the mapped area. Thickness patterns are controlled by paleostructural features such as the Poplar Dome, Nesson, Antelope, Cedar Creek, and Bottineau anticlines. Thinning and/or truncation occurs over the crest of the highs, and thickening of strata occurs on the flanks of the highs. The Three Forks can be subdivided into three units (up to six by some authors; e.g., Webster, 1984 ; Gutierrez, 2014 ; Gantyno, 2011 ). Most of the development activity in the Three Forks targets the upper Three Forks. The upper Three Forks is dominated by silt-sized quartz and dolomite and some very fine-grained sandstones and has low permeabilities and porosities. The upper Three Forks ranges in thickness from a wedge edge to over 40 ft (12 m) in areas east of the Nesson anticline. The unit thins toward the margins of the depositional basin because of erosional truncation. The upper and lower shale members are potential source rocks and are lithologically similar throughout much of the basin. The shales are regarded as dominantly type II kerogens. The shales average 11 wt.% total organic carbon. Measured core porosity and permeability are very low in the Bakken, Sanish, and Three Forks reservoirs (<10% porosity and <0.1 md permeability) in the Williston Basin, so productivity is assumed to be due to natural and artificial fracturing. The reservoirs generally require advanced technology to get them to produce (fracture stimulation and horizontal stimulation). For this reason, they should be considered to be technology reservoirs. Natural fractures in some areas (e.g., Billings Nose area and Antelope field) are sufficient for vertical well production. Reservoir pressure in the Bakken is regarded as overpressured with pressure gradients exceeding 0.5 psi/ft. A new pressure map for the Bakken petroleum system was generated. The map is based on 92 BHP (bottom-hole pressure) and DFIT (diagnostic fracture injection test) data points, including six additional hydrostatic points at the eastern margin as well as six data points for the Sanish–Parshall area. High overpressures are found in large parts of the central basin and the Parshall area in the east, where gradients exceed 0.7 psi/ft. Elm Coulee has a pressure gradient around 0.55 psi/ft. Parshall is reported to have a gradient of 0.74 psi/ft. The area west of the Nesson anticline has pressure gradients of 0.6 to 0.7 psi/ft. Pressure gradients in Montana are generally in the 0.51 psi/ft range.

Abstract Using conventional core samples from the Upper Devonian–Mississippian Bakken Formation, Williston Basin, North Dakota, U.S.A., and the Upper Cretaceous Niobrara Formation, Denver Basin, Colorado, U.S.A., as examples, the pore systems and the associated organic matter habit common in these source rocks and associated unconventional tight oil reservoirs are characterized. A workflow that distinguishes primary organic matter (kerogen) and secondary organic matter (bitumen and oil) based on their morphology, paragenesis, and general thermal history as interpreted from high-resolution scanning electron microscopy-based technologies is described in this chapter. In the description of this workflow, the quantitative image processing challenges of discriminating and quantifying pores and organic matter types are reviewed.