Page 40 - Formation Damage during Improved Oil Recovery Fundamentals and Applications

Low-Salinity Water Flooding: from Novel to Mature Technology 23

(McGuire et al., 2005); correlation of contact angles and IFT with salinity
(Ashraf et al., 2010; Yousef et al., 2010); the electrical double layers asso-
ciated with a thin film of saline formation water coating the clay minerals
of the rock matrix changing thickness in double layer expansion (DLE)
(Nasralla and Nasr-El-Din, 2012; Myint and Firoozabadi, 2015); and,
multicomponent ionic exchange (MIE) with the sandstone reservoir
21
becoming negatively charged (Fig. 2.1), partly due to Mg exchange,
with oil desorbing from the reservoir matrix due to repulsive charges
(Lager et al., 2008). Austad et al. (2010) suggested that potentially several
chemical mechanisms were at play in making LSWF effective.
There is a strong case to be made (Fig. 2.1) that both DLE and MIE
are the key underlying mechanisms, which complement each other and
not mutually exclusive, in enabling LSWF to incrementally improve oil
recovery. Changes in wettability, formation water pH, and composition
observed during LSWF are likely to be the effects of those underlying
mechanisms. The complex and varied bonding of the polar elements of
crude oil, some of which are displayed in Fig. 2.1, mean that there are
potentially many types of ion exchange reactions involved depending
on the composition of the oil, formation water, clay mineralogy, and
fabric (e.g., availability of potentially mobile fines particles) in the reser-
voir matrix.
The first LSWF field test (Webb et al., 2004), on a single producing
well in response to different water salinities injected into the reservoir,
reported 25 50% reductions in residual oil saturation attributed to water
flooding with low-salinity brine. That study concluded that as much as
50% additional oil could be produced from the well, if water with salinity
of ,4000 ppm was injected into the reservoir instead of sea water or
higher salinity produced water. The significance of salinity thresholds was
confirmed by multiwell field tests revealing that reservoirs flooded with
water salinities of .7000 ppm showed the least incremental oil recovery
(McGuire et al., 2005), which was supported by core studies (Zhang
et al., 2007). Another pilot well test suggested that the improved
incremental recovery was related to a reduction in the water cut of the
produced fluids, rather than an increase in oil production rate (Seccombe
et al., 2010).
Reservoir simulations applying salinity-dependent relative permeabil-
ity and capillary pressure functions (Jerauld et al., 2006), the addition of a
dual porosity model (Wu and Bai, 2009), and correlations of residual oil
saturation, contact angle, and IFT (Al-adasani and Bai, 2012)have