Southeastern Section - 60th Annual Meeting (23–25 March 2011)

Paper No. 5
Presentation Time: 9:20 AM


BECK, E. Glynn1, TAKACS, Kathryn G.2, PARRIS, T. Martin2, WEDDING, Daniel1 and LOCKE, Randy3, (1)Kentucky Geological Survey, University of Kentucky, 1401 Corporate Court, Henderson, KY 42420, (2)Kentucky Geological Survey, University of Kentucky, 228 Mining and Mineral Resources Building, Lexington, KY 40506-0107, (3)Illinois State Geological Survey, University of Illinois, 615 East PeaBody Drive, Champaign, IL 61820,

Between May 2009 and May 2010, 7,200 tons of carbon dioxide were continuously injected into a previously waterflooded Mississippian sandstone oil reservoir to evaluate the potential for tertiary oil recovery and carbon storage in western Kentucky. After CO2 injection, the Sugar Creek field was returned to a waterflood project. Before, during, and after CO2 injection, a variety of geochemical measurements were conducted to document the fate of CO2 in the subsurface and CO2-water-rock interactions. Documentation of the interactions is critical for understanding reactions that lead to sequestration such as solubility trapping and dissolution and precipitation reactions that might influence reservoir and seal properties. Reservoir pressure was monitored using pressure transducers installed at the oil field wells. An infrared gas analyzer was used to determine annular CO2 concentrations at production wells. In order to delineate aqueous geochemical changes within the reservoir, brine samples were collected from seven oil wells. In addition, three shallow groundwater monitoring wells, two domestic water wells, and one water-supply well were sampled to monitor any aqueous geochemical changes within the overlying freshwater aquifers. All wells were sampled for field measurements (pH, specific conductance, dissolved oxygen, temperature, and oxidation-reduction potential), total CO2, alkalinity, dissolved anions and metals, and total dissolved solids.

Free-phase CO2 migrated to five of the eight production wells surrounding the injector. Typically, after the arrival of CO2 to the wellbore (breakthrough), pH decreased one pH unit and chloride, calcium, strontium, and iron concentrations increased by 200 mg/L, 115 mg/L, 45 mg/L, and 2.5 mg/L, respectively. Barium concentrations decreased after breakthrough. Aqueous geochemical changes occurred less than 1 month to 4 months after CO2 breakthrough. Since CO2 injection was halted, pH values have generally remained below pre-injection values and other geochemical constituents have continued to increase in concentration. No geochemical changes have been observed within the overlying groundwater aquifers that would indicate CO2 leakage from the deeper reservoir formation. Post-CO2 injection sampling is scheduled to continue through May 2011.