Page 94 - Formation Damage during Improved Oil Recovery Fundamentals and Applications

76 Thomas Russell et al.

(Oliveira et al., 2014). The mathematical model assumes that fast parti-
cles move with the water velocity, so slow fines drift adds only one
unknown parameter to be determined from the laboratory tests. It is the
so-called delay drift factor α, which is the ratio between slow fines and
water velocities (Yang et al., 2016). The model exhibits an excellent
agreement with the laboratory data. Therefore, the drift fines velocity is
equal to αU, which must be used in mass balance and straining kinetics
equations.
Russell et al. (2017) undertook a systematic laboratory study of the
effect of kaolinite contents in the rock on fines-migration formation-
damage. Nonmonotonic permeability decrease versus decreasing injected
salinity has been observed. The results indicated that only 0.2 1.6% of
the kaolinite is movable by low-salinity and fresh-water injection.
Two-phase flow with varying salinity and fines detachment occurs
during displacement of oil by low-salinity (smart) waterflooding.
Saturation effects on fines detachment and transport are particle flow with
phase velocity of water (Yuan and Shapiro, 2011) and saturation-
dependency of the maximum retention function (Zeinijahromi et al.,
2013). Lemon et al. (2011) and Zeinijahromi et al. (2011) introduced
fines-migration formation-damage into the Dietz model for waterflood-
ing, for displacement regimes with a given rate and pressure drop, respec-
tively. The analytical model shows significant sweep enhancement due to
plugging of the swept zone.
Laboratory studies of low-salinity waterflooding in Berea sandstones
was undertaken by Hussain et al. (2013), and Zeinijahromi et al. (2016).
So-called double coreflood consists of oil displacement by formation-
water and resaturation of the core with further low-salinity water
injection. The Welge’s and Johnson-Bossler-Naumann (JBN) methods are
applied for the case of low-salinity water injection, yielding two pairs of
relative permeability for oil-formation water and for oil-injected water.
No fines release and ionic exchange occur during displacement by forma-
tion water, so this case is a base case, to compare other cases with.
Application of Welge’s and JBN methods to laboratory coreflood data
resulted in nonmonotonic water relative permeability as a function of sat-
uration. This unusual effect is explained by continuous sweep of new
rock surfaces by continuous water saturation increase that yields continu-
ous release of fines and growing permeability damage.
Mapping of basic equations for fines-assisted low-salinity waterflood-
ing on the polymer option of black-oil equations allows for 3D numerical