Abstract
<jats:title>Summary</jats:title> <jats:p>Large-scale offshore CO2 storage requires injection wells that can withstand strong thermal and pressure transients arising from cold CO2 injection and intermittent operating cycles. This paper presents an integrated modelling framework that couples a multiphase CO2 flow simulator with a thermo-mechanical finite-element model of the full wellbore structure. The workflow is applied to a representative North Sea CO2 injection well to quantify the effects of injection rate, reservoir pressure, and shut-in duration on casing, cement, and interface integrity.</jats:p> <jats:p>The simulations show that for given wellhead and injection conditions, wellbore cooling during injection is mainly dependent on reservoir pressure, with low-pressure reservoirs producing the strongest expansion cooling and thus the largest thermo-mechanical loads. Flow rate and injectivity primarily scale the magnitude of casing contraction, whereas reservoir pressure governs both temperature and wellbore pressure evolution. For the cases studied, the axial, radial, and hoop stresses in the production casing remained within API limits, but the large reversible stress ranges indicate that thermal fatigue may become a long-term integrity concern. Casing–cement contact pressure decreases sharply during injection due to thermal contraction and partially recovers during shut-in. The results also reveal that initial cement stress conditions strongly influence whether thermal unloading may lead to interface separation, especially if cement shrinkage reduces early-age confinement.</jats:p> <jats:p>The study provides new quantitative insight into the coupled thermo-mechanical response of CO2 wells and highlights the operational conditions most critical for maintaining long-term well integrity during CO2 injection.</jats:p>