Summary

Compared with a conventional reservoir, the ultralow permeability in the Bakken Formation makes it very challenging to perform normal waterflooding or gasflooding 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-dominated flow in the low-permeability matrix with high oil saturation. Improving hydrocarbon transport (and technically recoverable resources) in unconventional reservoirs relies on our ability to enhance diffusion-dominated flow from the oil-saturated matrix to the natural- or induced-fracture network, which is the focus of this study.

To unlock the unproduced Bakken and Three Forks oil, high-pressure carbon dioxide (CO2) may be used to enhance the diffusion-dominated flow in the matrix and keep the viscous flow in the fractures under reservoir temperature and pressure conditions (e.g., 230°F and 5,000 psi). Core samples were collected from two Bakken wells, including all oil-bearing intervals: Upper Bakken (UB), Middle Bakken (MB), and Lower Bakken (LB) Members and the Three Forks (TF) Formation. Detailed core analyses were performed to measure petrophysical properties and characterize these units. Ten samples were selected for pore-size-distribution 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” at reservoir conditions (rather than “flow through” tests) and were aimed at increasing our understanding of the microstructure and diffusion-dominated-flow ability within these tight geologic formations.

CO2-exposure and hydrocarbon-extraction experimental results clearly showed the improvement of diffusion-dominated flow in all the Bakken members. The UB and LB samples, characterized by generally high total-organic-carbon (TOC) content (10–15 wt%) and small pore size (approximately 3–7 nm), yielded approximately 60% of the present mature hydrocarbon at the end of the 24-hour exposure. The MB and TF samples, characterized by lower TOC content (<0.5 wt.%) and moderate pore size (approximately 8–80 nm), provided more-favorable flow conditions for CO2 and hydrocarbons, yielding approximately 90% of the mature-hydrocarbon content. Because all experiments were conducted at reservoir conditions, the results demonstrate that 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 shale-oil formations (high surface-area/volume ratio) where 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 where the fracture networks assist in alleviating potential injectivity challenges.

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