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Theoretical modeling of the effect of temperature on CO2 injectivity in deep saline formations

Yen Adams Sokama‐Neuyam, Francis Adu‐Boahene, Patrick Boakye, Wilberforce Nkrumah Aggrey and Jann Rune Ursin

Greenhouse Gases: Science and Technology, 2020, vol. 10, issue 1, 4-14

Abstract: Well injectivity and storage capacity defines the storage potential of a CO2 capture, utilization, and storage (CCUS) facility. Formation temperature has high impact on the phase behavior and flow properties of CO2 such as density and viscosity. The effect of temperature on CO2 injectivity, especially in the wellbore injection inlet, is not well understood. We investigated the thermal behavior of CO2 from the wellhead to the reservoir using simple theoretical models that capture the major heat transfer mechanisms. The effect of CO2 injection flow rate and injection time on the temperature of CO2 were studied. We found that for the same initial CO2 injection temperature and formation intake temperature, the injected CO2 in the well is cooler than the surrounding formation from the wellhead to the bottomhole. The temperature difference increased with increasing injection flow rate and injection time. The results show that although CO2 may attain supercritical state at bottomhole, the temperature difference between CO2 in the wellbore and the reservoir could be significant. The results also suggest that CO2 could attain thermal equilibrium with the reservoir at a flow distance of about 600 ft into the formation depending on the injection flow rate and reservoir temperature. The thermal disequilibrium of CO2 in the wellbore vicinity where fluxes are also high could affect CO2 injectivity and the mobility of CO2 during CCUS and enhanced oil recovery (EOR) operations. The present findings provide vital understanding of the effect of thermal instability on CO2 injectivity especially in the wellbore injection inlet. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Date: 2020
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