Page 288 - Enhanced Oil Recovery in Shale and Tight Reservoirs

EOR mechanisms of wettability alteration and its comparison with IFT 265

Thus, if s wa > s oa , and m o > m w , we have Conclusion 3:
If the volume of water imbibed into a dry core is lower than the oil vol-
ume imbibed into the same dry core (gas-liquid systems), the rock is oil-wet;
but if the volume of water imbibed into a dry core is larger than the oil vol-
ume imbibed into the same dry core (gas-liquid systems), the rock is not
necessarily water-wet (the water-wetness cannot be determined by
comparing the imbibition volumes).
Conclusions 2 and 3 can be used to explain the paradoxical wettability
data of Montney and Horn River shale samples reported by Lan et al.
(2015b). For the Montney shale samples, the water-wetting angle and oil-
wetting angle on the dry cores were 45 and 0 (shown in Table 9.6 later),

indicating oil-wet. The wetting indices for water were 0.26e0.42 (<0.5),
indicating oil-wet. And the water volumes imbibed into similar Montney
cores were lower than the imbibed oil volumes, as shown in their
Fig. 9.36, indicating oil-wet. All the above data consistently showed that
the Montney cores were oil-wet.
For the Horn River shale samples, the water contact angles were 37e73

(not higher than 90 ) and the oil contact angles were 0 (see Table 9.6 later),
indicating oil-wet. But the water wetting indices were 0.67e0.77 (>0.5),
indicating water-wet. According to Conclusion 2, these wetting angles
cannot be used to determine the wettability. Actually, according to the esti-
mated wetting angles in the corresponding water-oil-solid systems, those
shale samples were likely to be water-wet (see Table 9.6 later). The imbibed
water volumes into Horn River samples were higher than the imbibed oil
volumes, as shown in Fig. 9.37, indicating water-wet. According to Conclu-
sion 3, the shale samples were not necessarily water-wet. Therefore, their
data cannot consistently determine the wettability without using the Con-
clusions 2 and 3. However, Lan et al. (2015b) hypothesized that the higher
water imbibition volumes were due to imbibition-induced microfractures,
poor hydrophobic pore connection, and/or osmotic potential.
Liang et al. (2016) had similar observations for shale samples from Lower
Longmaxi formation in China. The contact angles for water were 12e37 at

elevated and normal temperatures, but the contact angles for oil were also

0 , indicating oil-wet. Actually, according to the estimated wetting angles
in the corresponding water-oil-solid systems, those shale samples were likely
to be water-wet (see Table 9.6 later). However, the water imbibition vol-
umes were higher than oil imbibition volumes, indicating water-wet by
the conventional misconception. Actually, according to Conclusion 3, the
samples were not necessarily water-wet.