Efforts to increase Bakken oil recovery factors above a few percent could include carbon dioxide (CO2) enhanced oil recovery (EOR). CO2 EOR processes are expected to be very different in tight reservoirs compared to conventional reservoirs. During CO2 EOR in conventional reservoirs, CO2 flows through the permeable rock matrix, and oil is mobilized by a combination of oil swelling, reduced viscosity, hydrocarbon stripping, and CO2 displacement especially when above the minimum miscibility pressure. In the Bakken, CO2 flow will be dominated by fracture flow, and not significantly through the rock matrix. Fracture-dominated CO2 flow could essentially eliminate the displacement mechanisms responsible for increased recovery in conventional reservoirs. As such, other mechanisms must be optimized in tight reservoirs such as the Bakken. Conceptual steps for the Bakken include: (1) CO2 flows into and through the fractures, (2) unfractured rock matrix is exposed to CO2 at fracture surfaces, (3) CO2 permeates the rock driven by pressure, carrying some hydrocarbon inward; however, the oil is also swelling and extruding some oil out of the pores, (4) oil migrates to the bulk CO2 in the fractures via swelling and reduced viscosity, and (5) as the CO2 pressure gradient gets smaller, oil production is slowly driven by concentration gradient diffusion from pores into the bulk CO2 in the fractures. To investigate these concepts, rock samples from the Middle Bakken (low permeability), Upper and Lower Bakken (very low permeability), and a conventional reservoir (high permeability) were exposed to CO2 at Bakken conditions of 110°C and 5000 psi (230°F, 34.5 MPa) to determine the effects of CO2 exposure time on hydrocarbon production. Varying geometries of each rock ranging from small (mm) "chips" to 1 cm-diameter rods were exposed for up to 96 hours, and mobilized hydrocarbons were collected for analysis. Nearly complete (>95%) hydrocarbon recovery occurs in hours from the middle Bakken reservoir rock, and even faster with the more permeable conventional matrices. Unexpectedly, nearly complete recovery of hydrocarbons can even be achieved from the very tight source shales from the Lower and Upper Bakken, but requires longer exposure times and smaller rock sample sizes (i.e., high surface area to volume ratio). These results demonstrate that CO2 is capable of recovering hydrocarbons from Bakken source and reservoir rock (i.e., the thermodynamics of CO2 oil recovery are favorable), but that long periods of exposure combined with high rock surface areas are required (i.e., the kinetics of the recovery process are slow). The present study reports experimental methods and the resultant data to investigate the proposed mechanisms that will control CO2 EOR in tight formations. Implications for CO2 EOR processes in unconventional reservoirs are discussed.

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The development of broadly applicable storage coefficients for determining CO2 storage resource/capacity estimates has been identified as a critical component for stakeholders to make informed decisions regarding the potential implementation of large-scale CO2 storage. While several evaluations have been conducted to determine CO2 storage resource/capacity estimates, they are the result of different methodologies, and a comparison of the results is often difficult and/or misleading. Thus the development of approaches and methods for developing CO2 storage estimates that can be applied to assessments at a wide range of scales has been identified as crucial to the advancement of broadly applicable and comparable "storage coefficients." At the heart of the matter is the fact that only a fraction of the pore space within any given geological formation will be available or amenable to CO2 storage. The purpose of a storage coefficient is to assign a value to that fraction of a given pore volume in which CO2 can be effectively stored. In order to develop broadly applicable storage coefficients, three methodologies for determining storage resource/capacity in deep saline formations were evaluated: two that can be applied to open systems and one for application in closed systems. In the end, effective storage coefficients were developed for application to deep saline formations at scales ranging from site-specific evaluations to entire formations. Real-world data sets and numerical modeling simulations were used to calculate storage coefficients at the site-specific scale for three lithologies, ten depositional environments, and five structural settings. These results can then be modified and translated into effective storage coefficients that can be applied at the formation scale for the three main lithologies. To develop estimates of effective storage resources for entire basins, estimates for each formation within the basin must be summed. This same methodology can be applied for estimating effective storage resources within state/provincial and national boundaries. In this way, the application of the broadly applicable effective storage coefficients developed by this project can be used to estimate the effective storage resource at levels ranging from site-specific to formation-level, ultimately spanning large sedimentary basins and even entire nations and continents. Introduction In recent years, the concept of mitigating global climate change through large-scale carbon capture and storage (CCS) into geologic media (saline formations, depleted hydrocarbon reservoirs, and unminable coal seams) has gained worldwide attention. Identifying potential geologic sinks for carbon dioxide (CO2) storage and developing reliable estimates of their storage resource/capacity is a critical component of determining the efficacy of CCS. While numerous evaluations have been conducted to develop storage resource/capacity estimates for geologic formations throughout the world, they are the product of several different methodologies, and comparison of the results of one evaluation to another is often difficult and misleading. The IEA Greenhouse Gas Research & Development (R&D) Programme (IEA-GHG) has been working closely with a wide variety of international organizations, including the U. S. Department of Energy (DOE) to develop approaches and methods for developing CO2 storage resource/capacity estimates that can be applied to assessments at the site-specific, local, regional, basin, and country scales. Recently, IEA-GHG and DOE have identified the development of technically robust storage coefficients as being crucial to the advancement of broadly applicable and comparable storage resource/capacity estimates at all scales.

Rock core samples (51) from multiple lithofacies and depths were collected from 10 wells located throughout the Bakken Petroleum System. Each 11.2 mm diameter core was exposed to CO 2 for 24 h at reservoir conditions of 34.5 MPa (5000 psi) and 110 °C in a pressurized apparatus designed to mimic the fracture-dominated flow expected to occur during a CO 2 injection into hydraulically fractured tight unconventional formations. The oil recovered from the rock samples was collected hourly by slowly depressurizing the CO 2 into a collection solvent, while maintaining both CO 2 pressure and temperature constant in the extraction chamber. Recoveries of light and heavy oils were validated by comparing rock samples before and after CO 2 exposure using the extended slow heating Rock-Eval analysis. Extractions of replicate core samples from Middle Bakken (MB) tight nonshale, Upper Bakken shale (UBS), and Lower Bakken shale (LBS) gave reproducible results, demonstrating that the 11.2 mm diameter cores represent the original 10.2 cm (4 in.) core, and that the extraction and associated analysis procedures are reproducible. Recoveries of oil from the Three Forks (TF) and all MB cores ranged from 65 to >99% after 7 h of exposure and exceeded 94% for all cores at 24 h, despite median pore throat radii of only about 13 nm (MB) to 26 nm (TF). Surprisingly, significant oil was obtained from UBS and LBS cores despite the median pore throat radii of only ca. 3.5 nm, sizes that approach molecular dimensions. Although all TF and MB reservoir rocks showed high oil recoveries, the oil obtained in 24 h from UBS and LBS source rocks varied greatly for different well locations and ranged from as low as 11% to as high as 80%. Data analysis of mineralogical components, including clays, carbonates, evaporates, feldspars, and pyrite, showed that these factors were not useful to predict oil recoveries. Both total organic carbon (4−15 wt % for shales and 0.1−0.4 wt % for TF and MB) and the pore throat radii appear to control oil recovery, though they were not predictive for individual UBS and LBS cores. Results from the 51 rock core samples demonstrate that CO 2 is capable of penetrating oil-bearing pores and displacing crude oil from the UBS and LBS source rocks as well as the MB and TF reservoir rocks.

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.

Enhanced oil recovery (EOR) processes using CO2 in tight unconventional plays like the Bakken Formation are expected to be very different from the processes which control EOR in conventional reservoirs. During CO2 EOR in conventional reservoirs, CO2 flows through the permeable rock, and the minimum miscibility pressure (MMP) is an important operational parameter for achieving a successful "miscible" flood. In contrast, in tight fractured systems like the Bakken, CO2 flow may be dominated by fracture flow, and not by CO2 flowing through the rock matrix as in a conventional reservoir flood. Since fracture-dominated CO2 flow could essentially eliminate the "flushing" mechanisms responsible for increased recovery in conventional reservoirs, operation at or slightly above MMP may or may not be relevant for the success of an EOR flood in such tight fractured reservoirs. To investigate this concept, capillary-rise vanishing interfacial tension (VIT) was used to measure MMP values for a typical Bakken crude oil (API gravity 41.5) with CO2, methane, and ethane at 110°C (230°F) typical for the reservoir. The effect of these different fluids, as well as the effect of pressures at, above, and well above MMP on recovering crude oil hydrocarbons was determined for small rock core samples from the productive Middle Bakken laminated zone as well as from Upper and Lower Bakken samples. Compared to the MMP value for CO2 of 2520 psi, MMP with methane nearly doubled at 4510 psi, but was nearly cut in 1/2 for ethane at 1360 psi. The recovery of crude oil hydrocarbons from both the Middle Bakken and Lower Bakken shale samples with 24-hour exposures to these fluids at reservoir pressures showed efficiencies that parallel the MMPs determined with each fluid; i.e., ethane yielded faster and more efficient recovery of the crude oil than CO2, but both CO2 and ethane were much more efficient than methane at recovering the crude oil from the 11-mm round rod rock samples. Although hydrocarbon recoveries from the rock samples paralleled each injectant's respective MMP values, extractions with CO2 at the MMP, and at ca. double and triple the MMP pressure showed much more efficient crude oil recoveries at higher pressures from both the Middle Bakken and Lower Bakken shale, demonstrating that EOR pressures much higher than the MMP could substantially increase oil recoveries in tight unconventional systems like the Bakken.

In part 1 (10.1021/acs.energyfuels.9b01177), CO 2 was used to recover oil from 51 source shale and reservoir mudrock cores collected from the Bakken Petroleum System in the Williston Basin. Oil hydrocarbon recoveries after 24 h exposures to CO 2 at reservoir pressure and temperature were >94% for the reservoir mudrock cores and ranged from a few percent to as much as 80% for the source shales depending on the well location. In part 2, the experimental parameters that control oil recoveries were investigated, and the results show that exposed rock surface areas and CO 2 contact times are primary factors controlling oil recovery at reservoir temperature and pressure. Compared to the 11.2 mm diameter rods used in part 1, increasing the surface area by splitting the rods into a stack of 2−3 mm thick "coins" doubled the oil recovery rates from both reservoir and source rocks, while further increasing the surface area using ground and sieved 1−3.4 mm samples at least tripled recovery rates. In addition, extending the exposure time for the 11.2 mm diameter source shale rods to 96 h yielded nearly complete oil recoveries (as did the 24 h exposures with the 1−3.4 mm samples), indicating that pore spaces in the source shales as well as the more permeable reservoir rocks can be accessed by the CO 2 and the associated oil hydrocarbons recovered. Higher CO 2 pressures yielded higher oil recoveries from both the reservoir rocks and source shales regardless of whether the exposure pressure was at or a little below, somewhat above, or substantially above the minimum miscibility pressure (MMP). Laboratory experiments also demonstrated that crude oil recoveries are based primarily on the ability of the CO 2 to penetrate the rock matrix and dissolve the oil hydrocarbons via hydrocarbon vaporization into the CO 2 phase rather than bulk physical processes (e.g., swelling, lowered viscosity, the physical "sweeping" effect) that are important in conventional CO 2 floods. Lighter hydrocarbons (e.g., C7 to C14) were recovered at much faster rates than heavier hydrocarbons (e.g., >C20) from all rock samples and geometries as well as for all CO 2 pressures tested, as might be expected because lighter hydrocarbons have both higher diffusion coefficients and higher solubilities in CO 2 than heavier hydrocarbons. Limiting the amount of CO 2 had little or no effect on the recovery rates of the lighter hydrocarbons but greatly reduced those of the heavier hydrocarbons. These two observations are consistent with a concentration-gradient-driven diffusion recovery mechanism. Laboratory results suggest that oil recovery in the Bakken play with CO 2 will be enhanced by longer soak times, larger exposed rock surface areas, and higher pressures.

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