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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a b s t r a c tWhile the majority of shale formations will serve as reservoir seals for stored anthropogenic carbon dioxide (CO 2 ), hydrocarbon-bearing shale formations may be potential geologic sinks after depletion through primary production. Here we present the United States-Department of Energy-National Energy Technology Laboratory (US-DOE-NETL) methodology for screening-level assessment of prospective CO 2 storage resources in shale using a volumetric equation. Volumetric resource estimates are produced from the bulk volume, porosity, and sorptivity of the shale and storage efficiency factors based on formationscale properties and petrophysical limitations on fluid transport. Prospective shale formations require: (1) prior hydrocarbon production using horizontal drilling and stimulation via staged, high-volume hydraulic fracturing, (2) depths sufficient to maintain CO 2 in a supercritical state, generally >800 m, and (3) an overlying seal. The US-DOE-NETL methodology accounts for storage of CO 2 in shale as a free fluid phase within fractures and matrix pores and as an sorbed phase on organic matter and clays. Uncertainties include but are not limited to poorly-constrained geologic variability in formation thickness, porosity, existing fluid content, organic richness, and mineralogy. Knowledge of how these parameters may be linked to depositional environments, facies, and diagenetic history of the shale will improve the understanding of pore-to-reservoir scale behavior, and provide improved estimates of prospective CO 2 storage.Published by Elsevier Ltd.

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