When gas condensate reservoirs are developed by pressure depletion, retrograde condensation occurs at pressure below the dew point of the condensate gas reservoir. The minimum saturation required for the flow of condensate in reservoir rocks is so-called critical flow condensate saturation (CFCS). We often want to know how much the CFCS is, about this, some study indicates the CFCS is 30–50%. Yet, field experience indicates the CFCS at much lower saturation of around 10%, particularly in the presence of connate water. Although this may be ignored in laboratory studies, it could significantly contribute to recovery at field scale.

An experimental equipment by ultrasonic has been established in order to directly determine the CFCS in core at high pressure fluid system. At first, we verify the way by applying different kinds of porous media (no media, filling media and synthetic media) and test the saturated vapor pressure of CO2 in them, then we use two real gas condensate and two synthetic cores (one : porosity 37.1%, permeability 1.44µm2, and another : porosity 38.6%, permeability 1.73 µm2) to determine the CFCS, we demarcate the connection between condensate saturation and ultrasonic signal and get the CFCS which one is 15%, another is 18%.


Relative permeability curve is one of the basic curves that are used in field exploitation. Yet, up to now, the real relative permeability curve of condensate reservoir still can't been directly measured since the present measurement techniques are limited, among which the biggest limitation is that there is no way to measure CFCS. Recent years, many studies were conducted on it, but the results are quite different. Some studies[1] indicate the CFCS is 30–50% while others[2] indicate the CFCS at much lower saturation of around 10%, particularly in the presence of connate water. Saeidi and Handy[3] studied the retrograde condensation of methane/propane mixtures in a horizontal sandstone core by depleting it to a maximum volumetric condensate dropout of 18% and did not observe condensate flow even with a 30% interstitial water saturation. Asar and Handy[4] determined gas and liquid relative permeabilities of a methane/propane mixture in a 0.19 µm2 permeability core at various pressure. They observed that the liquid saturation approaches zero as the liquid system approaches the critical condition and the interficial tension between the phases vanishes. They concluded that the liquid could flow at low liquid saturation in condensate reservoirs. Some reports indicate the presence of interstitial water remarkably affects the CFCS while some consider no effects. Knopp[6] compared gas flooding results on four cores with water saturation from 19.3 to 26.8%with those from water-free tests. Gas/oil saturations were not affected by the presence of water. Declaud et al[7] studied gas flooding in high-permeability sandstone cores(k1 to 1.5 µm2) and reported that the oil recovery and relative permeabilities were nearly identical with or without interstitial water saturation. The residual saturations were found to be very low at 3.5 to 6%. Dumore et al[8] studied the drainage of oil in Bentheim sandstones(k=2µm2) with and without interstitial water. The residual oil saturation decreased from 17 to 3% when a water saturation of 24% was restored in the core.

The cited reports envision the effect of interstitial water on CFCS completely diferently. The understanding of it is largely unresolved. Further study of it is very important especially for the exploitation of condensate gas cap reservoir. Explore reservoir by depletion and produce condensate along with oil rim if CFCS is low. Explore reservoir by keeping pressure above dew point to make sure no condensation takes place during production if CFCS is high.

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