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Well abandonment in the context of CO2 storage operations demands a mitigation strategy for CO2 leakage along the wellbore. To prevent possible CO2 transport toward the surface and to protect the wellbore material from contact with acid brine, we propose forming a salt seal around the wellbore at reservoir level, after CO2 injection into a depleted gas field. The mechanism of water evaporation into dry gas and subsequent salting‐out of the dissolved halite is a well‐known issue in hydrocarbon production. We propose alternating injection of brine and CO2 to facilitate intentional salt clogging of the reservoir. Salt clogging was studied with TOUGH2, simu‐lating multiple cycles of brine and CO2 injection. We developed two near‐well reservoir models – a homogeneous 2D model and a more complex heterogeneous 2D model – using certain characteristics of the K12‐B depleted gas field. The homogeneous 2D model yields a 50‐cm thick salt bank around the well and complete permeability impairment after eight cycles of brine‐CO2 injection. Addition of vertical permeability heterogeneities causes variation in the lateral extent of salt precipitation and hence vertical discontinuities in the salt bank. A carefully designed injection strategy – with more injection cycles and lower injection rates – improves the vertical sealing. Predictions of the amount of required clogging for effective sealing would benefit from more accurate porosity‐permeability relationships and insights in the long‐term stability of the salt bank regarding re‐dissolution. We conclude that alternating brine‐CO2 injection could be a promising method for intentional salt‐clogging of the near‐wellbore area. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd

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Driven by concerns for safe storage of CO2, substantial effort has been directed on wellbore integrity simulations over the last decade. Since large scale demonstrations of CO2 storage are planned for the near-future, numerical tools predicting wellbore integrity at field scale are essential to capture the processes of potential leakage and assist in designing leakage mitigation measures. Following this need, we developed a field-scale wellbore model incorporating (1) a de-bonded interface between cement and rock, (2) buoyancy/pressure driven (microannulus) flow of brine and CO2, (3) CO2 diffusion and reactivity with cement and (4) chemical cement-rock interaction. The model is aimed at predicting leakage through the microannulus and specifically at assessing methods for CO2 leakage remediation. The simulations show that for a low enough initial leakage rate, CO2 leakage is self-limiting due to natural sealing of the microannulus by mineral precipitation. With a high leakage rate, CO2 leakage results in progressive cement leaching. In case of sustained leakage, a CO2 reactive solution can be injected in the microannulus to induce calcite precipitation and block the leak path. The simulations showed full clogging of the leak path and increased sealing with time after remediation, indicating the robustness of the leakage remediation by mineral precipitation.

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