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.

Over 40 rock samples were obtained from six Bakken wells which penetrate through the major oil pay including two shale intervals: Upper and Lower Bakken, and two tight intervals that are the targets for drilling: Middle Bakken and Three Forks. Detailed petrographic and petrophysical analyses were performed on the samples to better correlate the extraction results with the physical and geochemical properties of the rocks. Round rods (11.2-mm diameter X ca. 30–40 mm long) drilled from each of the 40 samples were individually exposed in a "bath" of CO2 for 24 hours at reservoir temperature and pressure of 5000 psi and 230°F (34.5 MPa, 110°C), and the recovered crude oil hydrocarbons were collected periodically and analyzed to determine the rates and efficiencies of oil recovery. For the 26 Middle Bakken and Three Forks rocks, hydrocarbon recovery upon CO2 exposure averaged 86% after 7 hours, and 99% after 24 hours. Recoveries of the crude oil (not including kerogen) from the 15 Upper and Lower shales were surprisingly high with an average of 30% recovered after 7 hours, and 50% recovered after 24 hours. While the Middle Bakken and Three Forks TOC values were ca. 0.3 wt.% (similar to their crude oil content), TOCs for the Upper and Lower Bakken shales were typically 10 to 15 wt.%, with ca. one-tenth of that organic content being crude oil hydrocarbons as opposed to kerogen. The Upper and Lower shales also had significantly smaller pore throat sizes (averaging ca. 3 nm) than the Middle Bakken and Three Forks samples (which averaged ca. 10–26 nm). Additional studies are being performed to determine whether the small pore throat sizes (which approach molecular dimensions) and/or the sorption of crude oil hydrocarbons onto the kerogen in the Upper and Lower shales are responsible for the slower hydrocarbon recovery than that achieved from the Middle Bakken and Three Forks rocks under CO2 exposure. Currently, the main targets for horizontal drilling are Middle Bakken and Three Forks, where thousands of multistage hydraulically fractured wells have been drilled in the past decade. The high oil recovery factor observed in cores from these intervals, especially when compared to the 7% average recovery in the field, indicates the huge potential for oil recovery factor improvement in these units by increasing oil production based upon supercritical CO2 extraction.

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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 (<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.

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