It is well known that the deliverability of gas condensate wells can be impaired by the formation of a condensate bank once the bottomhole pressure drops below the dew-point. There have been many excellent laboratory studies on gas-condensate relative permeability that describe this phenomenon, but there are few integrated laboratory-simulation-field studies that compare systematic predictions to field performance.

We present extensive experimental relative permeability data sets on some sandstone reservoirs. These data span the krg/kro and capillary number parameter space. We discuss the experimental procedures, and the design of fluid systems that mimic reservoir fluids, but at lower temperatures. Next we demonstrate various steps involved in our approach by modeling a gas condensate well with field production history. Here we first measured relative permeability data on core samples from the reservoir and fit them to capillary number dependent relative permeability models. Then, we performed detailed single well compositional modeling with realistic geology and boundary conditions. Finally, we compared the predictions to actual production data, and found that the match was quite good. The productivity reduction was found to be in the range of 80%, the majority of which occurred in the initial phases of production. Our ability to reasonably predict the well performance has given us confidence that our approach, including measuring only the relevant portion of the relative permeability curves and using synthetic fluids, may be sufficient.


Gas condensate reservoirs typically consist of single phase gas at initial reservoir conditions. When the flowing bottomhole pressure falls below the dew-point of the reservoir fluid, liquid condensate builds up ("condensate banking") near the wellbore. Condensate banking leads to reduction in gas relative permeability and loss in well productivity, and this is well documented in several field and theoretical studies.

Several authors have designed experiments to measure the critical condensate saturation before condensate can flow, and have reported high values ranging from 20–80%. Kalaydjian et al.8 found similar behavior using model and reservoir fluids; however, Nagarajan et al. have recently noted differences in relative permeability behavior. Many investigators have observed improved relative permeabilities with reduced interfacial tension, typically important in near-critical gas condensate systems.

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