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The adsorption of silica nanoparticles onto representative mineral surfaces and at the decane/water interface was studied. The effects of particle size (the mean diameters from 5 to 75 nm), concentration and surface type on the adsorption were studied in detail. Silica nanoparticles with four different surfaces [unmodified, surface modified with anionic (sulfonate), cationic (quaternary ammonium (quat)) or nonionic (polyethylene glycol (PEG)) surfactant] were used. The zeta potential of these silica nanoparticles ranges from −79.8 to 15.3 mV. The shape of silica particles examined by a Hitachi-S5500 scanning transmission electron microscope (STEM) is quite spherical. The adsorption of all the nanoparticles (unmodified or surface modified) on quartz and calcite surfaces was found to be insignificant. We used interfacial tension (IFT) measurements to investigate the adsorption of silica nanoparticles at the decane/water interface. Unmodified nanoparticles or surface modified ones with sulfonate or quat do not significantly affect the IFT of the decane/water interface. It also does not appear that the particle size or concentration influences the IFT. However, the presence of PEG as a surface modifying material significantly reduces the IFT. The PEG surface modifier alone in an aqueous solution, without the nanoparticles, yields the same IFT reduction for an equivalent PEG concentration as that used for modifying the surface of nanoparticles. Contact angle measurements of a decane droplet on quartz or calcite plate immersed in water (or aqueous nanoparticle dispersion) showed a slight change in the contact angle in the presence of the studied nanoparticles. The results of contact angle measurements are in good agreement with experiments of adsorption of nanoparticles on mineral surfaces or decane/water interface. This study brings new insights into the understanding and modeling of the adsorption of surface-modified silica nanoparticles onto mineral surfaces and water/decane interface.

Significant productivity loss occurs in gas condensate reservoirs due to condensate and water accumulation near the production well. Our experimental study shows that gas relative permeability decreases by more than 95% due to liquid blockage (high water saturation along with condensate accumulation) and the reduction is even more pronounced in presence of mobile water. Significant advances have been made during this study to develop and extend a chemical treatment to reduce the damage caused by liquid blocking in gas condensate reservoirs. The treatment is composed of a non-ionic polymeric fluorochemical in a glycol/alcohol or glycol ether/alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and increases the gas relative permeability. It also reduces the liquid trapping in pores, which increases the relative permeability to oil or condensate and makes the removal of water blockage from treated zone easier. Selection of solvents to deliver the fluorochemical to the rock surface is critical to the success of the treatment, especially in the presence of high water saturation and high salinity brine. The treatment improved the gas and condensate relative permeabilities by a factor of about 2–4 on liquid blocked outcrop and reservoir sandstone rocks. The improvement in relative permeability after chemical treatment was quantified by performing coreflood experiments at reservoir conditions. The treatment also shows good durability against flowing gas, condensate, brine and solvent. We have developed a chemical treatment that shows great potential to increase production from liquid blocked gas wells with relatively small treatment volumes since only the near-well region needs to be treated. Introduction In gas condensate reservoirs a significant loss in the well productivity is observed when the bottomhole pressure in flowing wells falls below the dew point pressure of the fluid. The buildup of a condensate bank around the well impedes the flow of gas to the well and thus reduces its productivity. Water blocking can cause additional reduction in well deliverability of gas condensate wells. Water can be introduced into the formation during drilling, completion, or workover operations. Water can also flow into a gas-bearing zone from a high-pressure aquifer or a water-bearing zone. Liquids, including both condensate and water, are trapped in pores by capillary forces causing a significant reduction in gas relative permeability and this reduces well productivity. The loss in productivity can be even more pronounced in low permeability reservoirs as very high liquid saturations can be trapped in these reservoirs because of high capillary forces. The reduction in well productivity for gas condensate wells is generally a function of fluid phase behavior and the reduction in relative permeabilities in the near wellbore region. Both phenomena are complex and difficult to predict their effects under reservoir conditions, therefore a great deal of effort has been put into the study of both. Kokal et al. (2000), Pederson and Milter (2004) and Bang et al. (2006a) have studied the effect of water on the phase behavior of gas condensate fluids under reservoir conditions. Relative permeability studies have been done over a wide range of conditions with synthetic fluids (Henderson et al., 2000; Kumar, 2006; Ayyalasomayajula et al., 2003; Bang et al., 2006b) as well as with reservoir fluids (Nagarajan et al., 2004; Mott et al., 2000). Effect of various parameters such as capillary number, non-Darcy effects, fluid composition and rock type on gas relative permeability have been investigated.

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