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Geochemical Modeling Study of Shale–Brine–CO2 Interaction




Turkes, Ozan

Type of Degree

Master's Thesis



Restriction Status


Restriction Type

Auburn University Users

Date Available



A promising large-scale mitigation option for reducing CO2 footprint is Geological Carbon Sequestration (GCS) in depleted oil and gas reservoirs and deep saline aquifers. This study investigated the interaction between CO2 and shale caprocks during the process of geologic CO2 storage. CO2 is less dense than formation waters and thus its buoyancy provides a driving force for it to react with overlying caprocks and potentially escape back to the surface via fractures or abandoned wells. The trace element-rich shale caprocks could potentially pose a threat to overlying groundwater aquifers. To understand the potential risk, geochemical models were built after analyzing the shale samples from the Black Warrior Basin (BWB) by using XRD, XRF, Electron Microprobe, and ICP-MS. XRD, XRF, Electron Microprobe, and ICP-MS results showed that Conasauga Shale Shelby County sample is rich in carbonate minerals while Neal (Floyd) Shale Pickens County sample is rich in clay, silicate, and sulfide minerals. Conasauga Shale Claire County, Chattanooga Shale Greene County, and Devonian Shale Hale County samples contained various amounts of carbonate, silicate, clay, and sulfide minerals. Shales with significant silicate, clay, and sulfide minerals were relatively enriched in Al, Si, K, Na, V, Cu, Pb, Ni, Cr, Se, Zn, As, Be, and Co, whereas carbonate-bearing shales were enriched in Ca, Mg, and Sr. Geochemist’s Workbench was used to model potential mineral precipitation/dissolution and trace element mobilization via desorption and ion-exchange reactions during CO2 injection. The models indicate that carbonate mineral such as calcite readily dissolve, whereas silicates and clay minerals are only of secondary importance in dissolution. Calcite dissolution is the dominant reaction at the beginning of CO2 injection. The overall shale-brine-CO2 interaction would result in an increase in shale porosity. A higher calcite content decreased the dissolution of albite, k-feldspar, chlorite, illite, and the subsequent precipitation of dawsonite and kaolinite. A lower calcite content resulted in a lower pH at high CO2 fugacity. Geochemical modeling also shows that the pH drop results in the desorption of trace elements (e.g., Zn2+, Ni2+, and Co2+) from the surface of Fe(OH)3. Most of the desorption process occurs at low CO2 fugacity of 0-100 bar. Numerical models show that trace elements may be mobilized via ion-exchange reactions with clay minerals (illite) present in shales. The increasing calcite dissolution and Ca2+ concentration resulted in significantly more trace element mobilization due to ionic competition on exchanging sites. Geochemical models also revealed different trace element mobilization behaviors. Sr2+ and Co2+ were significantly influenced by ion-exchange reactions and increased ion concentration in the fluid, whereas Ni2+ and Zn2+ were mainly affected by the sorption processes and change in pH.