A CO₂ Sequestration Simulation Case Study at the Dickman Field, Ness Co., Kansas

Since 2006 the University of Houston has evaluated CO₂ sequestration potential in a deep saline aquifer system in Ness County, Kansas. This paper is a summary on the simulation part of the project.

Combining 3D seismic and dense well control, a static model was constructed and history matching was accomplished.Good history matching validates the static geological model and the same model can then be further used for CO₂ sequestration prediction.

After history matching, several aquifer simulation models were constructed to study the CO₂ injection rate and storage safety issues. A full formation simulation model including sallow geological layers and deep saline aquifer was further constructed to predict CO₂ migration after injection. Free CO₂ gas trapped in a geological structure can migrate to the surface through faults, fractures, failed cap rock, or corroded well pipe. These actions represent a real safety threat. A major challenge is to develop a practical simulation model to study CO₂ leakage scenarios over long time periods (typically 250 years in our work). One way of improving CO₂ storage safety is to accelerate residual gas and solubility trapping. Our simulation results indicate two effective ways of reducing free CO₂: injecting CO₂ with brine, and/or horizontal well injection. In the carbonate aquifer we studied, tuned combination of these methods can reduce the amount of free CO₂ from over 50% to less than 10%.

As part of the lower Paleozoic aquifer system in Kansas, Missouri and Oklahoma, the site under the Dickman oil field shows potential as a viable CO₂ storage site. However, faulting and numerous abandoned wells cast uncertainty on its ability to serve as a permanent CO₂ storage site. This study shows that a careful simulation study can maximize CO₂ injection rate, minimize existence of free CO₂, and significantly reduce uncertainty in the safety of CO₂ permanent storage.