Sugar Creek oil field in the Illinois Basin of western Kentucky was the site of a carbon dioxide (CO2) Enhanced Oil Recovery (EOR)-sequestration pilot project conducted by the Midwest Geological Sequestration Consortium. From May 2009 to May 2010 approximately 7,230 tons of CO2 were injected into the Mississippian Jackson Sandstone at rates of 20 to 30 tons per day. Injection into the Jackson reservoir at 1,850 ft occurred through a central injection well surrounded by six to eight production wells. Using Sugar Creek as one of several pilot analogs, the overall project goal was to assess the potential for EOR in conjunction with storage of CO2 under immiscible conditions for mature oil fields in the Illinois Basin. Geologic characterization and engineering measurements were conducted before, during, and after CO2 injection to document the reservoir response to injection and fate of injected CO2. Data were interpreted largely within the framework of a geocellular model constructed from open-hole geophysical logs (n= 37) and archived porosity (average= 16%) and permeability (average= 19.5 mD) measurements. The geocellular model also provided input for reservoir models used to simulate EOR, storage capacity, and CO2 fate. Monitoring, Verification, and Accounting (MVA) tasks ensured project activities protected human health and local water resources. MVA tasks also documented migration of CO2 in the Jackson reservoir and the reservoir response. Bottom-hole pressure measurements at the injection well ensured that CO2 was injected safely and recorded reservoir pressure response to increasing CO2 saturation over the course of the project. Surface pressure measurements at production and monitoring wells (n= 11), along with bulk and isotopic chemistry measurements of gas and brine co-produced with oil, mapped the movement of CO2 and attendant geochemical interactions. Pressure changes and elevated CO2 concentrations were measured at five production wells within the first five months of CO2 injection. Elevated CO2 concentrations in the annulus gas were accompanied closely in time by decreases in brine pH, indicating rapid dissolution of CO2 into the brine. Increased alkalinity and dissolved inorganic carbon indicated some solubility trapping of CO2. Following the end of CO2 injection, the field was returned to a water flood, which remains ongoing. Measurements of gas composition and rates through September 2011 show that an estimated 16% (1,133 tons) of CO2 was produced at the surface. This implies that 84% of CO2 was stored in the reservoir at the time of analysis. The oil response analysis shows about 9,900 barrels of improved oil recovery and 2,700 to 3,200 barrels of EOR. Reservoir modeling projections suggest that full-field CO2 injection for 20 years could recover 5.5% incremental oil (~174,000 barrels) with a CO2 net utilization of 880 standard cubic feet/barrel oil.
|Original language||English (US)|
|Title of host publication||Abstracts - AAPG, Eastern Section Meeting|
|Publisher||American Association of Petroleum Geologists. Eastern Section, varies], United States|
|State||Published - 2012|