Evaluation of trapping mechanisms in geologic CO2 sequestration: Case study of SACROC northern platform, a 35-year CO2 injection site

Abstract

CO₂ trapping mechanisms in geologic sequestration are the specific processes that hold CO₂ underground in porous formations after it is injected. The main trapping mechanisms of interest include (1) fundamental confinement of mobile CO₂ phase under low-permeability caprocks, or stratigraphic trapping, (2) conversion of CO₂ to mineral precipitates, or mineral trapping, (3) dissolution in <i>in situ</i> fluid, or solubility trapping, and (4) trapping by surface tension (capillary force) and, correspondingly, remaining in porous media as an immobile CO₂ phase, or residual CO₂ trapping. The purpose of this work is to evaluate and quantify the competing roles of these different trapping mechanisms, including the relative amounts of storage by each. For the sake of providing a realistic appraisal, we conducted our analyses on a case study site, the SACROC Unit in the Permian basin of western Texas. CO₂ has been injected in the subsurface at the SACROC Unit for more than 35 years for the purpose of enhanced oil recovery. Our analysis of the SACROC production and injection history data suggests that about 93 million metric tons of CO₂ were injected and about 38 million metric tons were produced from 1972 to 2005. As a result, a simple mass-balance suggests that the SACROC Unit has accumulated approximately 55 million metric tons of CO₂. Our study specifically focuses on the northern platform area of the SACROC Unit where about 7 million metric tons of CO₂ is stored. In the model describing the SACROC northern platform, porosity distributions were defined from extensive analyses of both 3-D seismic surveys and calibrated well logging data from 368 locations. Permeability distributions were estimated from determined porosity fields using a rock-fabric classification approach. The developed 3-D geocellular model representing the SACROC northern platform consists of over 9.4 million elements that characterize detailed 3-D heterogeneous reservoir geology. To facilitate simulation using conventional personal computers, we upscaled the 9.4 million elements model using a “renormalization” technique to reduce it to 15,470 elements. Analysis of groundwater chemistry from both the oil production formations (Cisco and Canyon Groups) and the formation above the sealing caprock suggests that the Wolfcamp Shale Formation performs well as a caprock at the SACROC Unit. However, results of geochemical mixing models also suggest that a small amount of shallow groundwater may be contaminated by reservoir brine possibly due to: (1) downward recharge of recycled reservoir brine from brine pits at the surface, or (2) upward leakage of CO₂-saturated reservoir brine through the Wolfcamp Shale Formation. Using the upscaled 3-D geocellular model with detailed fluid injection/production history data and a vast amount of field data, we developed two separate models to evaluate competing CO₂ trapping mechanisms at the SACROC northern platform. The first model simulated CO₂ trapping mechanisms in a reservoir saturated with brine only. The second model simulated CO₂ trapping mechanisms in a reservoir saturated with both brine and oil. CO₂ trapping mechanisms in the brine-only model show distinctive stages accompanying injection and post-injection periods. In the 30-year injection period from 1972 to 2002, the amount of mobile CO₂ increased to 5.0 million metric tons without increasing immobile CO_2, and the mass of solubility-trapped CO₂ sharply rose to 1.7 million metric tons. After CO₂ injection ceased, the amount of mobile CO₂ dramatically decreased and the amount of immobile CO₂ increased. Relatively small amounts of mineral precipitation (less than 0.2 million metric tons of CO₂ equivalent) occurred after 200 years. In the brine-plus-oil model, dissolution of CO₂ in oil (oil-solubility trapping) and mobile CO₂ dominated during the entire simulation period. While supercritical-phase CO₂ is mobile near the injection wells due to the high CO₂ saturation, it behaves like residually trapped CO₂ because of the small density contrast between oil and CO₂. In summary, the brine-only model reflected dominance by residual CO₂ trapping over the long term, while CO₂ in the brine-plus-oil model was dominated by oil-solubility trapping.