Joule-Thomson cooling during CO2 injection into low-pressure fields can lead to injectivity impairment due to hydrate formation. This paper presents axial-symmetric flow model, which can be used to predict propagation of temperature and CO2 fronts during CO2 injection into porous formations accounting for Joule-Thomson cooling and unsteady-state delayed heat exchange between the reservoir and the adjacent formations. The solution of the 1D flow is validated by comparing with the quasi 2D analytical heat-conductivity solution. The non-steady state heat exchange results in a temperature front that propagates without limit into the reservoir with time. The temperature profiles exhibit a temperature decrease from the injected temperature to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The solution allows plotting temperature-pressure (T-P) profiles at fixed moments in the CO2-water phase diagram. By changing injection parameters such as injection rate, the T-P trajectories allow for assessment of hydrate formation.

This paper discusses axi-symmetric flow during CO₂ injection into a non-adiabatic reservoir accounting for Joule-Thomson cooling and steady-state heat exchange between the reservoir and the adjacent layers by Newton's law. An exact solution for this 1D problem is derived and a new method for model validation by comparison with quasi 2D analytical heat-conductivity solution is developed. The temperature profile obtained by the analytical solution shows a temperature decrease to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The temperature distribution head of the front is determined by the initial reservoir temperature, while the solution behind the front is determined by the temperature of injected CO₂. The analytical model exhibits stabilisation of the temperature profile and the cooled zone. The explicit formula for temperature distributions allows determining the maximum injection rate that avoids hydrate formation.

The success of CO2 storage projects largely depends on addressing formation damage, such as salt precipitation, hydrate formation, and fines migration. While analytical models for reservoir behaviour during CO2 storage in aquifers and depleted gas fields are widely available, models addressing formation damage and injectivity decline are scarce. This work aims to develop an analytical model for CO2 injection in a layer-cake reservoir, considering permeability damage. We extend Dietz’s model for gravity-dominant flows by incorporating an abrupt permeability decrease upon the gas-water interface arrival in each layer. The exact Buckley-Leverett solution of the averaged quasi-2D (x, z) problem provides explicit formulae for sweep efficiency, well impedance, and skin factor of the injection well. Our findings reveal that despite the induced permeability decline and subsequent well impedance increase, reservoir sweep efficiency improves, enhancing storage capacity by involving a larger rock volume in CO2 sequestration. The formation damage factor d, representing the ratio between damaged and initial permeabilities, varies from 0.016 in highly damaged rock to 1 in undamaged rock, resulting in a sweep efficiency enhancement from 1–3% to 50–53%. The developed analytical model was applied to predict CO2 injection into a depleted gas field.