Pressure, temperature, and saturation changes

Duri engineers estimate that steam is injected into the reservoir at the wellbore at about 430 $^{\circ}$F and 350 psia. At the steam front between steam and hot condensate, the pressure and temperature may initially be about 250 psia and 350 $^{\circ}$F, and later drop to 135 psia and 350 $^{\circ}$F as the steamflood matures Bee et al. (1994). Residual oil saturation in the steam zone is estimated to be about 10% with gas saturation at 90%. In the hot water and hot oil annulus, temperatures drop off between the steamfront values and ambient reservoir values of 100 $^{\circ}$F and 100 psia. Residual oil saturation may be as high as 20%, and gas saturation is probably negligible. In the pressure-front region, pressure values of 110 psia or more will be above bubble point at an ambient temperature 100 $^{\circ}$F. Residual gas saturation is likely to be negligible since initial gas in pores space crosses the bubble point and dissolves into liquid oil (path AB of Figure 10). The pressure, temperature and gas saturation changes expected in the reservoir during steam injection are tabulated in Table 2 respectively.

 

$$\Delta \Delta \Delta$$ ZONE P (psia) T (F) Sg (%)

steam 250 +150 350 +250 90 +80

hot water 200 +100 250 +150 -10

hot oil 175 +75 175 +75 -10

pressure front 150 +50 100 +0 -10

ambient 100 -- 100 -- 10 --

 

 

hc-phase
Figure 10 Hydrocarbon phase diagram in the Pressure-Temperature plane with contours of liquid oil saturation relative to gas. CP is the critical point (after Dake, 1978).