Residual gas saturation controls the volume of gas trapped in that portion of the reservoir that has experienced water encroachment. As water moves into a rock volume filled with gas, the water displacement of the gas is incomplete. The water fills pores and pore throats, causing capillary pressure and relative permeability effects to stop the flow of gas and allow only water to pass through the rock volume. This stoppage results in gas being trapped behind the encroaching waterfront as residual gas. The volume and location of the residual gas are controlled by the distribution of the petrophysical properties.
A method based on interrelationships between petrophysical properties is used to create a model for calculating maximum residual gas saturation (Sgrm). The model is developed as a function of porosity, permeability, capillary pressure, and initial water saturation. The input to the model and its results compare favorably with actual field data where aquifer encroachment is verified from well production history.
Maximum residual gas saturation (Sgrm) is what initially results from imbibition on rock at irreducible water saturation (Swirr). Sgrm results from gas acting as the nonwetting phase during imbibition hysteresis as pressure is depleted in a gas reservoir and an aquifer encroaches in pore space that was once filled with gas. Because Sgrm normally occurs from aquifer influx into a gas reservoir, it causes a reduction in reservoir recovery efficiency. The range of Sgrm is extensive, varying from 0.1 to 0.7.1,2
Numerous influences may affect Sgrm:
how the wetting fluid gets in (either forced or spontaneous imbibition),
type of wetting fluid,
rate of imbibition,
rock type (lithology, grain size and sorting),
wettability and interfacial tensions,
temperature and pressure conditions, and
petrophysical properties (porosity, permeability, initial gas saturation). The effects each of these has on Sgrm have been studied, although a unifying theory describing Sgrm has yet to be produced.
Neither the mechanism nor the imbibing fluids seem to affect the resulting Sgrm value. Geffen et al.3 demonstrated that Sgrm values were similar for either forced or spontaneous imbibition. Cromwell et al.4 demonstrated this phenomenon in Boise sandstone. Geffen et al.3 showed that the wetting phase in conjunction with gas did not affect the value of Sgrm obtained. Jerauld5 and Kyte et al.6 substantiated this result. The rate of imbibition by the wetting phase also seems to have little effect on the value of Sgrm obtained.4,7,8
This conclusion follows from the observation that neither forced nor spontaneous imbibition significantly affects the value of Sgrm because both occur at different rates.
Rock and pore type can have a strong affect on the value of Sgrm, and variations in carbonate rock types can also significantly affect Sgrm.2,9 Sgrm increases with an increase in clay content in sandstones and decreases in sorting and grain size.5,10 In a dual-fractured pore network system Sgrm can be quite high.11 These results intuitively seem correct because Sgrm is a capillary phenomenon and these rock characteristics that appear to increase Sgrm also increase pore network complexity.
The effect of wettability and interfacial tensions in an oil-water system can be profound, although in a gas-water system there is less variation and thus less effect. Crowell4 reported that a decrease in interfacial tension between wetting and nonwetting phases results in a slight decrease in Sgrm.