Determination of Relative Permeability and Recovery for North Sea Gas Condensate Reservoirs

Laboratory experiments on gas condensate flow behavior were conducted under reservoir conditions. Two North Sea gas condensate reservoirs that have distinct rock and fluid properties were studied. The objectives of the corefloods were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities during in-situ condensation, hydrocarbon recovery and trapping by water injection, and incremental hydrocarbon recovery by subsequent blowdown. It was found that both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate drop out can be somewhat restored by increasing production rate. Phase behavior and interfacial tension influence the extents of gas relative permeability reduction and condensate mobility. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Approximately 27 %PV gas was trapped by water injection. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant.