Modeling Reservoir Rock and Formation Fluid Geochemical Interactions: Implications for CO2 Sequestration from Citronelle Oil Field, Alabama
Weislogel, Amy; Donahoe, Rona J.; Case, George; Coffindaffer, Keith; Donovan, Theodore
The Citronelle field in southwest Alabama, is the site of a U.S. Department of Energy pilot project on long-term geologic storage of CO2 and the efficacy of CO2-EOR. The target for injection is the Donovan Sand, an assemblage of arkosic fluvial sandstones intercalated with mudstones within the Lower Cretaceous Rodessa Formation. Following injection in Nov. 2009, production from updip well Permit 706 increased 20% to 493 bbl/month in 3 months. However, after Feb. 2010, monthly production decreased by 50% to 250 bbl/month, and has not been >300 bbl/month as of March 2012, despite water-flooding beginning March 2010. Reservoir rock samples from 6 cored wells were analyzed via thin-section petrography, bulk geochemistry, and SEM-EDS to model reservoir rock composition. Sand mineralogy is uniform but authigenic mineralogy and porosity are heterogeneous. Porosity averages ~2-5%, but locally is up to ~13%. A total of 47 SP well logs were used to estimate of bulk density, from which an estimated porosity curve and porosity distribution map were generated. Paragenesis indicates early calcite cementation and later calcite cement dissolution combined with feldspar alteration generated secondary porosity. In contrast, authigenic clay is rare suggesting an open diagenetic system during feldspar alteration. A later generation of anhydrite and calcite concretions and pyrobitumen occludes both primary and secondary pores. Formation fluids collected during late CO2 injection and the subsequent water-flood, show increases in the concentrations of Br, Ca, and Fe, along with pH decreases for most wells. Saturation indices for minerals in the reservoir rock do not indicate mineral dissolution reactions could cause the observed element concentration trends. Instead, ion exchange reactions between H+ sourced from carbonic acid generated by injected CO2 and cations on the surfaces of reservoir minerals is likely occuring. A simplified TOUGHREACT model of fluid flow was unable to simulate the observed breakthrough times for CO2 in any of the observation wells, suggesting the primary fluid transport pathway may be fracture-controlled; thus, fluids may interact with minerals of non-porous lithologies or may generate redistributional porosity/mineral trapping in calcite-cemented zones. Iron fouling or possibly interactions between calcite and acidic formation fluid may have caused observed lowered injectivity during water-flooding.
AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013