Improving Oil Transportability Using CO2 in the Bakken System – A Laboratory Investigation
Authors: Jin Lu , Sorensen James A. , Hawthorne Steven B. , Smith Steven A. , Bosshart Nicholas W. , Burton-Kelly Matthew E. , Miller David J. , Grabanski Carol B. , Harju John A. 
Published: January 2016

Abstract
The Bakken Petroleum System (BPS) is defined as the stratigraphic sequence of rocks, in order of deposition, from the Upper Three Forks Formation through the Upper Bakken Formation. The system is a complex mixture of shale, clastic, and carbonate rock types deposited in a marine environment during the late Devonian Period. The system is considered to be unconventional in that it consists of ultralow permeability and requires mechanical stimulation for production to occur. However, the system is somewhat conventional and is differentiated from other gas shale plays in North America in that it currently produces light sweet oil (40 API) from the carbonate/clastic mixture of rocks of the Upper Three Forks and Middle Bakken Formations. The shales of the Upper and Lower Bakken Formation are considered the source for the system.
Compared to a conventional reservoir, the ultralow permeability in the BPS makes it very challenging to carry out normal water or gas flooding operations. "Permeability jail" effects cause low injectivity and prevent injected fluids from sweeping oil out of the matrix efficiently. Two distinguishable flow regimes have been identified in fractured, hydrocarbon-rich shale formations: viscous flow in high-permeability fracture networks and diffusion flow in the low-permeability matrix with high oil saturation. Improving hydrocarbon transport (and technically recoverable reserves) in unconventional reservoirs relies on our ability to enhance diffusion flow from the oil-saturated matrix to the natural or induced fracture network, which is the focus of this study.
To access unproduced oil of the BPS, high-pressure CO2 may be used to enhance the diffusion flow in the matrix and keep the viscous flow in the fractures under reservoir temperature and pressure conditions (e.g., 5000 psi and 230°F). Core samples were collected from two wells, representing the Upper Bakken shale, Middle Bakken mixed clastic carbonate, Lower Bakken shale, and the mixed clastic carbonate Three Forks Formation. Detailed core analyses were performed to determine the petrographic and petrophysical properties of these units. Ten samples were selected for pore-size distribution (PSD) measurement, and 21 samples (11-mm-diameter rods) were used for 24-hour CO2 exposures and hydrocarbon recovery experiments. These experiments were conducted as CO2 "bathing" (rather than "flow-through" tests) and were aimed at increasing our understanding of the changes in microstructure and diffusion flowability within these tight geologic formations.
CO2 exposure and hydrocarbon extraction clearly showed the improvement of diffusion flow in all of the BPS samples tested. Upper and Lower Bakken shale samples, characterized by generally high total organic carbon content (TOC ~12–15 wt%) and small pore size (~3–8 nm), yielded approximately 60% of the present mature hydrocarbon at the end of the 24-hour exposure. Middle Bakken and Three Forks samples, characterized by lower TOC content (&lt;0.5 wt%) and moderate pore size (~10–80 nm), provided more favorable flow conditions for CO2 and hydrocarbons, yielding approximately 90% of the mature hydrocarbon content. As all experiments were conducted at reservoir conditions, the results demonstrate that molecular diffusion plays a significant role in the mobilization of oil in tight reservoirs.
CO2 greatly enhances the diffusion process to improve hydrocarbon transport in the tight matrix. This observation is especially useful for densely fractured formations (high surface area-to-volume ratio) where 1) CO2 has greater areal contact with the reservoir, enabling CO2 diffusion into the matrix and hydrocarbon diffusion out of the matrix to occur more efficiently (increasing recoverable reserves) and 2) the fracture networks assist in alleviating potential injectivity challenges.