Interactions of CO2 with formation waters, oil and minerals and CO2 storage at the Weyburn IEA EOR site, Saskatchewan, Canada

Abstract The Weyburn oil field in Saskatchewan, Canada, is hosted in Mississippian carbonates and has been subject to injection of CO 2 since 2000. A detailed mineralogy study was completed as the basis for modeling of mineral storage of injected CO 2 . Combining the mineralogy with kinetic reaction path models and water chemistry allows estimates of mineral storage of CO 2 over 50 years of injection. These results, combined with estimates of pore volume, solubility of CO 2 in oil and saline formation waters, and the initial and final pore volume saturation with respect to oil, saline water and gas/supercritical fluid allow an estimate of CO 2 stored in saline water, oil and minerals over 50 years of CO 2 injection. Most injected CO 2 is stored in oil (6.5 × 10 6 –1.3 × 10 7  t), followed closely by storage in supercritical CO 2 (7.2 × 10 6  t) with saline formation water (1.5–2 × 10 6  t) and mineral storage (2–6 × 10 5  t) being the smallest sinks. If the mineral dawsonite forms, as modeling suggests, the majority of CO 2 dissolved in oil and saline formation water will be redistributed into minerals over a period of approximately 5000 years. The composition of produced fluids from a baseline sampling program, when compared to produced fluids taken three years after injection commenced, suggest that dawsonite is increasingly stable as pH decreases due to CO 2 injection. The results suggest that hydrocarbon reservoirs that contain low gravity oil and little or no initial gas saturation prior to CO 2 injection, may store the majority of injected CO 2 solubilized in oil, making such reservoirs the preferred targets for combined enhanced oil recovery-CO 2 storage projects.