Effect of High Reynolds and Capillary Numbers on Over-Pressured Rich Gas Condensate Reservoir Development

Abstract

Abstract Gas deliverability is one of the key issues in gas condensate reservoirs. Simulations have shown that the severity of the well impairment due to the effects of inertia at high velocity can be over predicted, if the benefits of positive coupling associated with condensing fluids is not taken into account and the dependence of relative permeability on the capillary number is ignored. An extensive modelling study has been carried out to evaluate the impact of the subsurface uncertainties on the performance of a typical over-pressured rich gas condensate reservoir. The viscous stripping effect was modelled by allowing the relative permeability curves to be dependent on the capillary number. The subsurface development concepts were selected based on a cumulative distribution function of condensate recovery generated by a multi-run technique. Different sensitivities were tested to investigate the impact on gas and condensate ultimate recovery. The results from compositional single well radial model confirm a build-up of oil saturation at various distances from the wellbore with a decrease in gas saturation values as the reservoir pressure falls below the dew point pressure. Areal upscaling and absolute permeability variation have an important effect on production profiles. Increasing number of wells shows that three optimal wells are sufficient to develop the whole reservoir. The same ultimate recovery has been reached by these wells using different maximum well offtakes. As a conclusion, for over-pressured rich gas condensate reservoirs with good sand permeability, a combination of high Reynolds and capillary numbers results in gas relative permeability increase and a reduction in residual condensate saturation near the wellbore. Then, the condensate banking near the wellbore is reduced and this type of reservoirs can be developed by less optimal number of wells compared to others with low sand permeability. Introduction Gas deliverability is one of the key issues in gas condensate reservoirs. Simulations have shown that the severity of the well impairment due to the effects of inertia at high velocity can be over predicted, if the benefits of positive coupling associated with condensing fluids is not taken into account and the dependence of relative permeability on the capillary number is ignored [1]. As hydrocarbon exploration moves to deeper geological formations, volatile oil and gas condensate reservoirs become increasingly important. At initial reservoir conditions, the hydrocarbon fluids in these reservoirs are often found at near-critical conditions. As a consequence, the physical properties of the oil phase and the gas phase are very similar and the interfacial tension between oil and gas is very low. The latter may have an important bearing on the multiphase flow characteristics in the reservoir during the production phase where retrograde condensation can occur in the near well-bore region if the pressure falls below the dew point. The condensate liquid partially blocks the gas flow channels and reduces gas productivity [2–7].