Seawater Depleted in NaCl as a ‘Smarter’ Enhanced Oil Recovery Fluid in Carbonates
Figure 5: Initial Wettability Test on a Core Saturated with Crude Oil, Water-wet Fraction = 0.53, Synthetic Seawater Containing Tracer and SO42-(SSW1T)
1.00 0.75 0.50 0.25 0.00 0.0 0.5 C/Co SCN- A = 0.083 1.0 PV injected C/Co SO4 2- A ref = 0.156
SO4 2- Ref WI = 0.53
SCN- Ref
Figure 6: Wettability Test After Spontaneous Imbibition Using Synthetic Seawater Diluted to 10,000ppm (Dil-SSW10000) at 110ºC, Water-wet Fraction = 0.52, Synthetic Seawater Containing Tracer and SO42- (SSW1/2T)
1.00 0.75 0.50 0.25 0.00 0.0 0.5 C/Co SCN- 1.0 C/Co SO4 2- A = 0.167 A ref = 0.324 2 1.5 PV injected
SO4 2- Ref WI = 0.52
(SSW1/2T). SCN- Ref
Wettability test after spontaneous imbibition using synthetic seawater diluted to 10,000ppm (Dil-SSW10000) at 110ºC, Water-wet fraction = 0.52, synthetic seawater containing tracer and SO4
Figure 7: Wettability Test After Spontaneous Imbibition Using Synthetic Seawater at 110ºC, Water-wet Fraction = 0.64, Synthetic Seawater Containing Tracer and SO42 (SSW1/2T)
1.00 0.75 0.50 0.25 0.00 0.0 0.5 C/Co SCN- 1.0 C/Co SO4 2- A = 0.265 described previously.7 A ref = 0.324 1.5 PV injected
SO4 2- Ref WI = 0.82
SCN- Ref 2.0 2.5 A chalk core flooded with SSW at 130ºC with
a rate of 3 pore volume (PV)/D for one day was used as a reference core for a completely water-wet system.
72
determined to be 0.324. After spontaneous imbibition of SSW, DilSSW10000 and SSW0NaCl at 110°C, the area between the tracer and the sulphate curve was calculated to be 0.207, 0.167 and 0.265, respectively. The corresponding water-wet fractions were 0.64, 0.52 and 0.82, as shown in Table 3. Thus, using SSW as the imbibing fluid, the water-wet area was increased by 11 %. The diluted seawater, Dil- SSW10000, did not increase the water-wet area at all. Seawater depleted in NaCl (SSW0NaCl) appeared to have the greatest effect on the wetting properties by increasing the water-wet area by 29 %. Thus, the change in wetting properties was completely in line with the imbibition tests shown in Figure 3.
EXPLORATION & PRODUCTION – VOLUME 9 ISSUE 2 2.0 2.5
Wetting tests for the cores after spontaneous imbibition using DilSSW10000, SSW and SSW0NaCl are shown in Figures 2 to 8. First, the cores were flooded with SW0T to achieve residual oil saturation. Next, the cores were flooded with SW1/2T, and the effluent was collected in fractions. The area for the chromatographic separation between the tracer and sulphate for the reference core was
The imbibition rate and ultimate oil recovery increased relative to ordinary seawater when the imbibing seawater was depleted in NaCl.
1.5 2.0 2.5
Figure 8: Wettability Test After Spontaneous Imbibition Using NaCl-depleted Synthetic Seawater (SSW0NaCl) at 110ºC, Water- wet Fraction = 0.82, Synthetic Seawater Containing Tracer and SO4
2 (SSW1/2T) 1.00 0.75 0.50 0.25 0.00 0.0 0.5 C/Co SCN- 1.0 C/Co SO4 2- A = 0.265 A ref = 0.324 1.5 PV injected
SO4 2- Ref WI = 0.82
SCN- Ref
The initial wetting condition of the cores used for the imbibition tests was determined from the test shown in Figure 2. The reference core and the core aged in crude oil with initial Valhall brine were flooded at
room temperature with SSW0T to remove SO42- and to establish residual oil saturation. Afterwards, the cores were flooded with SW1T
(containing SO42- and the tracers SCN-) at the rate of 0.2ml/minute, and the effluent was collected. The calculated area between the elution curves was 0.156 and 0.083 for the complete water-wet core and the core aged in crude oil, respectively. The initial water-wet fraction (WI) was calculated as 0.083/0.156 = 0.53, which correspond to a neutral wetting condition (see Table 3).
2.0 2.5
C/Co
C/Co
C/Co
C/Co
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