Field Study of the Condensate Banking Effect in an Unconventional Gas Condensate Reservoir with Hydraulically Fractured Wells

Abstract As unconventional assets mature, gas condensate reservoirs are increasingly being targeted for development. However, gas condensate reservoirs are prone to wellbore productivity losses due to a two-phase flow caused by condensate banking when pressures drop below the dewpoint. Conventional reservoir mitigation strategies minimize condensate banking by maintaining flowing bottomhole pressures close to dewpoint pressures. However, using this approach with unconventional reservoirs raises concerns, as primary depletions and hydraulic fractures in long horizontal wells make maintaining dewpoint pressures implausible. Therefore, to provide a more effective mitigation solution for optimal field development, the severities of unconventional well condensate banking must be reevaluated. This paper investigates condensate banking effects on well performance by conducting field modeling studies on Delaware Basin deep Wolfcamp condensate producers using compositional simulation models with hydraulic fractures. Three-dimensional (3D) geologic models were constructed based on facies distributions. Fracture models were based on high-fidelity geomechanical models. A 11-component Equation of State (EOS) model was calibrated using a pressure/volume/temperature (PVT) sample. Full field reservoir simulation models were built to match well pressure and production rates. The models found condensate banking to be of minimal concern, as condensate dropped out mostly in fracture networks and could be efficiently produced through highly conductive fractures. An optimal development plan with an aggressive flowback strategy, validated by actual Permian Basin gas condensate well performance, is therefore proposed, which should improve the project value without a condensate banking risk.