Recently some core flood experimental data were reported following a new CO2 Huff-n-Puff (H-n-P) injection technique. This technique optimized CO2 injection pressure and volume to improve CO2/resident fluid interactions for enhanced gas and condensate recovery and CO2 storage purposes. This simulation study aims to complement and generalize the corresponding core flood experimental results. The simulation data confirm the dominant governing mechanism and the importance of using appropriate CO2/gas-condensate kr data while accounting for the effect of compositional changes on gas and condensate mobility during CO2 H-n-P injection. Laboratory PVT tests were performed to generate relevant data sets that describe the complex phase behavior changes when CO2 interacts with gas condensate systems. These data sets were applied for EOS tuning, phase behavior prediction, and quantifying the level of CO2/gas condensate interactions. A CO2 H-n-P injection core-flood simulation model was developed. H-n-P injection cycles with the incremental injection of CO2 volumes were simulated to replicate experimental procedures performed on a high-permeability Berea sandstone core. Experimental data showed that conventional CO2 H-n-P injection treatment significantly improves hydrocarbon gas and condensate recovery efficiency but at the cost of injecting and producing high volumes of CO2. While the proposed method applied at the maximum condensate saturation for the corresponding CO2/gas-condensate mixture can match the recovery efficiency achieved when applying the conventional injection technique, but with much lesser volumes of CO2 injected and produced. The relative permeability data measured for gas and condensate fluids (GC-kr) were significantly affected by the compositional changes resulting from CO2/resident fluid interactions below the saturation pressure. The numerical model predicted a close match for the pressure profile after adjusting the GC-kr data. However, it could only match the production profile for the pre-CO2 and first CO2 injection cycle, where the volume of CO2 injected was small and had a negligible effect on condensate recovered relative to the volume of condensate in place. Sensitivity analyses were performed on GC-kr data attempting to history match the experimental and simulated data. The generated data were analyzed to quantify the effects of CO2/resident fluid interactions on condensate revaporization and the model's predictability. These data will aid in bridging the gap in the level of CO2/gas-condensate interactions during CO2 flooding, which is vital for designing an efficient CO2 H-n-P injection process.

Recovery from gas condensate reservoirs, when the pressure is below dew point pressure (Pdew), is adversely affected by the accumulation of condensate in the near wellbore region. The mitigation of the near-well bore condensate banking is the main purpose of any enhanced recovery method implemented in gas condensate reservoirs. In this work, a new method was tested to improve condensate recovery by using a chemical that was delivered using hydrocarbon gas as a carrier into a very low permeability and very low porosity reservoir rock. Chemicals are typically injected using liquid carrier solvents. The use of hydrocarbon gas as the carrier provides a remedy to mitigate condensate banking in very low permeability cores by minimizing complications associated with low injectivity and back flow clean-up process requirements of an injected liquid. The chemical potential was evaluated by recording production data from unsteady-state coreflood experiments. The injection of the chemical with equilibrated gas resulted in condensate saturation to decrease from 19.6% to 6.5%. This decrease was not instantaneous and took some time to occur indicating that the chemical needs time to interact with the resident fluid and rock. The benefit of the method, at the field scale, was also estimated by performing single-well numerical simulations that use relative permeability (kr) data which history matched the measured coreflood production data. The results of these preliminary simulations also showed improved recovery of gas and condensate compared to pure depletion, without chemical, by around 40% for the cases considered.