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.
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.
We report here a simplification of the capillary-rise/vanishing interfacial tension (IFT) method to measure minimum miscibility pressure (MMP) based on only requiring knowledge of when the interfacial tension approaches zero. Simply measuring the height of the crude oil in a capillary at several pressures from ambient to near the MMP pressure and extrapolating the oil height versus pressure plot to zero oil height yields the MMP without the need of the additional instrumentation and labor required to perform actual IFT measurements. A total of 2–4 MMP values can be determined per day with only one experimental apparatus, and the method greatly reduces the initial cost and complexity of the required instrumentation. The use of three capillaries having different inner diameters allows for triplicate determinations of MMP from each experiment. Because the actual MMP pressure need not be reached during the experiment, MMP values that exceed the pressure ratings of the equipment can be reasonably estimated (e.g., MMPs using pure nitrogen). The method was used to determine the MMP pressure for crude oil samples from a conventional Muddy Formation reservoir in the Powder River Basin [American Petroleum Institute (API) gravity of 35.8°] and an unconventional Bakken Formation reservoir in the Williston Basin (API gravity of 38.7°). The method is reproducible [typically <4% relative standard deviation (RSD)], and the method gave good agreement for a “live” Bakken oil with the results from a slim tube test of a commercial laboratory. Approximately 80 MMP values were measured using pure CO2, methane, and ethane as well as 0–100% mole ratios of methane/CO2 and methane/ethane. For both oil samples, ethane MMPs were ca. one-half those with CO2, while methane MMPs were ca. double or triple those with CO2. MMPs with mixed methane/CO2 showed a linear increase with mole percent methane for both crude oils, while both oils showed an exponential increase in MMP with mole percent methane in ethane, with a little increase in MMP until ca. 20 mol % methane in ethane.
This work analyzes a database of 31 existing CO 2 enhanced oil recovery (EOR) projects that was compiled for the estimation of oil reserves to better understand the CO 2 retention, incremental oil recovery, and net CO 2 utilization for these oil fields. The measured data begin at the start date of the CO 2 flood and extend through the year 2007. Cumulative CO 2 retention (in the formation), incremental oil recovery factors, and net CO 2 utilization factors were calculated for each of the sites. To express all site data on a common dimensionless scale, the data were extrapolated to 300% cumulative hydrocarbon pore volume (HCPV) by fitting nonlinear functions. Summary statistics were then calculated from 0% to 300% HCPV. Across all 31 sites, the 10th, 50th (median), and 90th percentile values for the three factors at 300% HCPV were:
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