Abstract
Many gas condensate reservoirs suffer a loss in productivity owing to accumulation of liquid in near-wellbore region. Wettability alteration of reservoir rock from liquid-wetting to gas-wetting appears to be a promising technique for elimination of the condensate blockage. In this paper, we report use of a superamphiphobic nanofluid containing TiO2 nanoparticles and low surface energy materials as polytetrafluoroethylene and trichloro(1H,1H,2H,2H-perfluorooctyl)silane to change the wettability of the carbonate reservoir rock to ultra gas-wetting. The utilization of nanofluid in the wettability alteration of carbonate rocks to gas-wetting in core scale has not been reported already and is still an ongoing issue. Contact angle measurements was conducted to investigate the wettability of carbonate core plugs in presence of nanofluid. It was found that the novel formulated nanofluid used in this work can remarkably change the wettability of the rock from both strongly water- and oil-wetting to highly gas-wetting condition. The adsorption of nanoparticles on the rock and formation of nano/submicron surface roughness was verified by Scanning Electron Microscope (SEM) and Stylus Profilometer (SP) analyses. Using free imbibition test, we showed that the nanofluid can imbibe interestingly into the core sample, resulting in notable ultimate gas-condensate liquid recovery. Moreover, we studied the effect of nanofluid on relative permeability and recovery performance of gas/water and gas/oil systems for a carbonate core. The result of coreflooding tests demonstrates that the relative permeability of both gas and liquid phase increased significantly as well as the liquid phase recovery enhanced greatly after the wettability alteration to gas-wetting.
Highlights
In gas condensate reservoirs, when the pressure of reservoir drops below the dew point, a condensate phase forms and flows along with the gas phase in the reservoir as its saturation reaches or exceeds the critical condensate saturation
Considering these data, it can be deduced that the superamphiphobic TiO2 nanofluid has increased the water and oil contact angle to a much greater degree than the chemicals reported in the former studies [5, 8, 9, 13,14,15,16,17]
As it is obvious from the results, no sensible difference could be perceived between the contact angle of distilled water and brine, and the contact angle of n-decane and gas-condensate as well
Summary
In gas condensate reservoirs, when the pressure of reservoir drops below the dew point, a condensate phase forms and flows along with the gas phase in the reservoir as its saturation reaches or exceeds the critical condensate saturation. The condensate will accumulate gradually and become trapped in near wellbore region. This accumulation of liquid which is known as condensate banking or condensate blockage, results in reduced gas and condensate production rates and sharp lowered well deliverability [1, 2]. Condensate can be mobilized from formation around the wellbore by either increasing the drawdown pressure (viscous forces) or lowering capillary pressure. The capillary pressure (PC) is proportional to contact angle (h), interfacial tension (r) and reversely proportional to pore size (r), according to Young-Laplace equation.
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