  Condensate banking around wellbores can significantly shorten the production
from gas-condensate reservoirs. Different approaches to mitigate this issue
have been proposed in the literature, among which gas injection comes out with
promising results. With this method, pressure maintenance and condensate
re-vaporization can be achieved, lessening the flow blockage caused by liquid
dropout and accumulation in the porous medium. While gas injection in
gas-condensate reservoirs has been largely investigated at the meso and macro
scales, data regarding the method's efficiency at the micro-scale are scarce.
Therefore, the effects of local changes in gas and condensate properties
stemmed from the interaction between injected and reservoir fluids at the
pore-scale are poorly understood. In order to evaluate how these changes affect
the transport in porous media, a compositional pore-network model was used to
reproduce gas injection in a sandstone sample following condensate
accumulation. C1, C2, CO2, N2, and produced gas were tested as the candidates
for condensate banking remediation at different pressure levels. After gas
flooding, condensate saturation, heavy component recovery, and gas relative
permeability were quantified to appraise the achieved gas flow improvement. The
results indicated that C2 and CO2 were the most effective gases to clear the
accumulated condensate and re-establish the gas flow. Conversely, C1 and N2,
especially mixed with the produced fluids, displayed the least favorable
results, and could even lead to gas flow impairment.
