Page 64 - Formation Damage during Improved Oil Recovery Fundamentals and Applications

46 David A. Wood and Bin Yuan

Figure 2.14 Sensitivity of Berea sandstone to salt concentration of injected fluids
determined by core flooding experiments to reveal the CSC for that formation. K o
refers to initial permeability. Adapted after Khilar and Fogler (1984).

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• Light crude oil with density 0.83 g/cm and viscosity 3.3 cp; and
• Artificial brines made up with fresh water and NaCl to produce injec-
tion fluids with salinities varying from 30,000 to 200,000 ppm.
The study did not address fluids with salinities of ,30,000 ppm (i.e.,
these are significantly above the CSC required to induce LSW sensitivity,
Fig. 2.14) nor the influence of salts other than NaCl.
Despite the limitations (with respect to LSW conditions), Salehi
et al. (2017) recorded a range of impacts related to a higher range of
salinities for the injection water on oil recovery, reservoir pressure drop,
reservoir permeability, IFT, viscosity, density, resistivity, pH,and relative
permeability during the water-flooding process. Their results indicated
that oil recovery increased as the injected water salinity increased (reach-
ing 48% for 200,000 ppm water salinity). In addition, IFT decreased with
increasing water salinity and both oil and water relative permeabilities
curves moved toward higher water saturations as water salinity increased.
This study highlights why historical many water floods conducted in
secondary recovery mode have elected to use high-salinity (e.g., sea
water) injection water.
Capillary forces play a significant role in limiting oil recovery effi-
ciency during water flood displacement processes. Melrose and Brander
(1974) identified that capillary forces are responsible for trapping between