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Carbon dioxide (CO 2 ) capture and storage (CCS) is a key climate mitigation technology that can global CO 2 emissions by thousands of megatonnes of CO 2 annually. CCS is almost certainly required, along with a wide portfolio of other technologies in an “all of the above” strategy, to achieve the reductions in global CO 2 emissions necessary to stabilize atmospheric concentrations of CO 2 . Despite many high-profile demonstration projects, commercial-scale CCS deployment is still impeded by multiple issues including economic viability, public awareness and acceptance, and regulation and permitting. Developing a large-scale, highly visible and economically feasible CCS network—in addition to existing investment approaches— will be required to overcome these barriers to widespread CCS adoption. We propose a pathway to an integrated CCS network that connects multiple industrial CO 2 sources and geologic storage reservoirs using existing CCS technologies. Specifically, we propose that such a network could utilize CO 2 emissions from ethylene manufacturing for enhanced oil recovery (EOR) in the U.S. Gulf Coast region, creating a regional ethylene:CO 2 -EOR network. The ethylene market presents several key advantages for capturing CO 2 : ethylene is a high-value chemical with a price that can readily absorb capture costs (unlike fossil fuel electricity generation), ethylene sources are both closely clustered and emit a large volume of CO 2 , and existing capture technology is cost-competitive when coupled with nearby EOR reservoirs. Our analysis describes the techno-economic potential of CO 2 capture and EOR, the potential policy implications, and how the ethylene industry could be an ideal first-mover for jumpstarting commercial-scale CCS operations. As part of this analysis we identify the costs and CO 2 flows for ethylene production and EOR across the Gulf Coast region. We introduce the concepts of “byproduct CO 2” (CO 2 as a byproduct or waste stream from an existing industry such as power generation) and “extracted CO 2” (naturally-occurring CO 2 extracted from subsurface reservoirs for EOR); extracted CO 2 cannot decrease the carbon footprint of oil production, unlike byproduct CO 2 . We also suggest ethylene:CO 2 -EOR as a blueprint for other regional-scale byproduct CO 2 -EOR projects such as the Alberta oil sands, Marcellus and other U.S. shale fields, and large-scale coal-to-liquid and coal-to-chemical operations in China.

Optimizing uncertainty reduction in evaluations of geological CO2 storage site scenarios requires a robust database that allows an accurate reconstruction of the targeted storage rock/fluid volume, especially with respect to spatial heterogeneity. Previous numerical simulations of the Rock Springs Uplift site (southwest Wyoming, USA) relied on a generalized regional database to populate a homogenous rock/fluid volume based on average reservoir properties. The results from this approach yielded general insights into injection/storage characteristics but lacked specificity, resulting in performance assessments plagued by substantial uncertainty. To move from idealistic, highly generalized assessments to realistic, low-risk assessments of the Rock Springs Uplift, it was necessary to acquire high-resolution data specific to the storage site of interest (carbonate and sandstone reservoirs, and confining layers in an 8 km × 8 km area). The foundation of the new database is a 4,000-meter-deep stratigraphic test well, an 8 km × 8 km 3-D seismic survey, 290 meters of high-quality core, a specialized log suite, fluid samples, and a diverse set of analytical laboratory measurements. These data made it possible to correlate seismic attributes with observations from log suites, a VSP survey, core, fluid samples, and laboratory analyses, including continuous permeability scans. From seismic data, 3-D spatial distribution volumes of reservoir and confining layer properties were constructed that represent geological heterogeneity at the targeted CO2 storage site. Consequently, the latest numerical simulations and performance assessments are characterized by substantially lower geological uncertainties. The new CO2 plume migration simulations for a set of defined CO2 injection rates and volumes occupy larger rock/fluid volumes and display pronounced marginal irregularities when compared to early simulations derived from homogenous reservoir parameter volumes. The spatial distributions of the injected CO2 plumes in previous simulations are conical with few marginal irregularities, whereas in the new simulations, the CO2 plumes occupy a larger up-dip volume and display pronounced marginal irregularities. These irregularities denote zones of higher porosity and permeability, such as collapsed breccias associated with karst zones and/or dolomitized grainstone zones in the Madison Limestone. Using the new numerical simulations which include heterogeneous rock/fluid parameter distributions, it is apparent that in all injection/storage scenarios of > 1 Mt/year CO2, substantial displaced fluid production/treatment is essential to manage pressure and maintain the integrity of confining layers. The total dissolved solids concentrations of the formation fluids retrieved from the Madison Limestone range from 80,000 to 90,000 ppm, and will necessitate customized water treatment strategies and facilities at the surface. The new data and upgraded evaluations demonstrate that the Rock Springs Uplift in southwestern Wyoming remains an outstanding large-scale geological CO2 storage site, and provides a realistic basis for designing commercial CO2 injection/storage operations on the Uplift. The 2010 U.S. Environmental Protection Agency Greenhouse Gas Reporting Program reports that in the Greater Green River Basin of southwest Wyoming, the CO2 emissions from stationary sources (sources that emit more than 25,000 tons of CO2 per year) total 29+ million tons annually, or approximately 50 percent of Wyoming's annual CO2 emissions. These CO2 sources include coal-fired power plants, gas and trona processing plants, pipeline compression stations, chemical production facilities, and gas-field complexes, among others. The Rock Springs Uplift in the center of the Greater Green River Basin is ideally located to serve as a large-scale commercial geological CO2 storage facility for half of all of Wyoming's industrial CO2 emissions. The new numerical simulations suggest that the Madison Limestone has the ability to permanently store the annual CO2 emissions from stationary sources in the Greater Green River Basin for 130 years (i.e., a total of 3.8 billion tons). The overlying Paleozoic Weber Sandstone on the Rock Springs Uplift has additional commercial-scale CO2 storage capacity. The Rock Springs Uplift has the attributes to serve as a regional CO2 storage site, and importantly, this site could be used as a storage/surge tank to supply CO2 to EOR projects throughout Wyoming.

Extraction of in-situ water is one of the options for minimizing the impact of large-scale CO 2 injection in saline aquifers or during enhanced oil recovery (EOR). The amount of water to be produced could be significant depending on in-situ conditions and injection parameters. Evaluating the costs of treatment is complex, as the quality of the water may vary considerably from treatments based on well-known seawater chemistry, including reverse osmosis. We evaluated a brackish-salinity water to be extracted from a future CO 2 injection and storage location in eastern China for prototype treatment costs for both cooling water and boiler water final treatment goals. Costs for treatment of the water, excluding costs for organic pretreatment, were within the range of previously analyzed costs for higher-salinity waters (US$1.53-6.20) but are likely to be lower when economies of scale are included for a full-scale, higher volume treatment facility. Importance analysis lends insight into process factors that may not contribute the highest unit costs to treatment but on whole are very important to total system costs. We found that the acid rate for pretreatment, zero-liquid discharge disposal, feed water temperature, and water transportation costs, were the most important factors within total system costs for this analysis.