Carbon dioxide (CO2) can be injected into the subsurface for the purpose of enhanced oil recovery (EOR), possibly with geological CO2 storage. This procedure brings about a set of unique challenges with respect to well construction, operation and remediation. As compared to normal production, CO2 injection imposes lower temperatures and stronger temperature variations on wells. This is especially prevalent if the injection is not continuous. Downhole temperature variations will result in expansion or contraction of casings and well barrier materials, which can cause them to crack or de-bond at interfaces. To avoid leakage paths through wells it is therefore important to understand within which temperature intervals it is safe to operate.

In the present paper we describe a heat-conduction model for calculating heat transfer from the well to the casing, annular seal and rock formation. These materials have dissimilar thermal properties, and will behave differently upon downhole temperature variations. The model is discretized using a finite-volume method developed especially for accurate calculation of heat conducted radially in a well. This allows us to predict temperatures and temperature variations at various locations in and around a given well during CO2 injection.

To verify the numerical model, we compare our simulation results with the time-varying temperatures measured in our laboratory. Good agreement is found between the numerical predictions and the measured data. Simulation results are presented for different combinations of formations and well barrier materials (cement and alternative types of annular sealants) to display their effect on the well temperature. It is found that by replacing cement with an annular sealant material with higher thermal conductivity, the temperature difference between the casing/seal interface and the seal/rock interface can be significantly reduced. A high-conductivity formation such as halite/rock salt can also reduce thermal gradients in the well materials.

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