The synergetic effect of salinity and fluorochemicals on the alteration of wettability from water-wetting to intermediate gas-wetting is studied in this work. We find that NaCl salinity increases water-wetting when a core is saturated with brine. NaCl also reduces absolute gas permeability as reported in the literature. CaCl2 salinity is drastically different from NaCl brine, and has a minor effect on permeability. The NaCl, KCl and CaCl2 brines have an adverse effect on wettability alteration. To alleviate the effect of salt on treatment, we suggest pre-treatment by displacement of brine with water and subsequent drainage by nitrogen.


A reduction in effective gas permeability observed in tight formations and in low permeability gas reservoirs is often attributed to water blocking and condensate accumulation. The water blocking is induced by the injection of water in hydraulic fracturing (Engineer, 1985; Cimolai, et al. 1993). The condensate accumulates at the wellbore as the pressure drops below the dew-point pressure (Barnum et al. 1995; El-Banbi et al. 2000). A major factor of liquid retention in a rock is the liquid's low mobility due to strong liquid wetting (Anderson, 1987a, b). By altering the wettability of the rock from liquid-wetting to intermediate gas-wetting, an increase in liquid mobility can be achieved resulting in a high rate of gas production. In 2000, Li and Firoozabadi pioneered the alteration of wettability by fluorochemical treatment, and demonstrated significant changes in contact angle, and imbibition testing for cores after treatment. Following their work, there have been a number of experimental studies on wettability alteration to intermediate gas-wetting (Tang and Firoozabadi, 2002, 2003; Kumar et al. 2006; Fahes and Firoozabadi, 2007; Panga et al. 2007; Al-Anazi, et al. 2007). Most of the work on wettability alteration has been performed by injection of chemicals into a core initially saturated with air or nitrogen, i.e., the dry core. In some cases the rock has been saturated with water or oils.

The reservoir rock before the chemical treatment is partially saturated with liquid condensate and the aqueous phase that may be connate water, condensed water from the gas, or from the aquifer. There is always a definite amount of ions in the subsurface water. For example, condensed water from gas may have 140–150 mg/l of chloride ion, and the fracturing fluid water may have ~ 25 mg/l chloride ion. One of the main parameters in wettability and imbibition studies is the water composition that can affect the wettability. Based on spontaneous imbibition and waterflooding tests at reservoir temperature in Berea sandstone with three crude oils and three reservoir brines, Tang and Morrow (1997) found that the salinity of the connate water and invading brines can have a major influence on wettability and oil recovery. Zhang and Austad (2006) verified that the ions Ca2+ and SO42- could increase the water-wetting of chalk, and thereby increase the water-oil capillary pressure of matrix blocks. There is an abrupt change in the zeta potential when only small amounts of ions are added to the aqueous solution. Tweheyo et al. (2006) have studied the effect of divalent ions on wettability alteration of carbonates and the subsequent effect on oil recovery by spontaneous imbibition. They found that SO42-, Ca2+ and Mg2+ ions can change the wettability to more water wetting at 100ºC and above without surfactants in the system. The three divalent ions seem to play different effects in the two processes: wettability alteration and spontaneous imbibition.

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