Browsing by Subject "Improved oil recovery"
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Item Experimental evaluation of nanoparticles impact on displacement dynamics for water-wet and oil-wet porous media(2015-08) Alghamdi, Abdullah Ali L; DiCarlo, David Anthony, 1969-; Bryant, Steven LThe potential of utilizing nanoparticles for production enhancement during oil-water displacement can play a significant role to achieve efficient and sustainable production of resources as they have shown great promise in stabilizing emulsion inside porous media. Furthermore, the displacement of brine solution containing nanoparticles by another non-wetting phase such as n-octane under water-wet condition has been shown to produce the signs of nanoparticle-stabilized emulsion. Because it is hypothesized that emulsion effects are caused by pore scale events that shear the fluids, this research aims to evaluate the impact of nanoparticles on different displacement scenarios (primary imbibition, primary drainage, secondary imbibition, and secondary drainage) and address the effect of wettability (oil-wet vs. water-wet), displacement types (different pore scale processes), and viscous stability (lower viscosity n-octane vs. higher viscosity tetradecane) on the generation of nanoparticle-stabilized emulsion in situ during immiscible displacement. Studying the impact of these changes is of primary importance since they contribute to changing pore scale events, fluids positioning and distribution, and displacement stability. Nanoparticle-stabilized emulsion has been associated with some indirect observable signs which include i) a rapid pressure drop increase exceeding the viscosity ratio between the brine and brine-nanoparticle dispersion, ii) a later breakthrough, , iii) a reduction in resident fluid residual saturation, and iv) a reduction of the invading phase endpoint relative permeability. Therefore, the impact of nanoparticles on the displacement was evaluated by measuring pressure drop data and effluent fluid histories. Those data were used to indicate the signs of nanoparticle-stabilized emulsion generation by interpreting pressure drop trends, water saturation histories, pressure drop ratio profile, residual fluid saturation, and endpoint relative permeability of the invading phase. Furthermore, the study attempts to examine the hypothesis that the displacement of a wetting hydrocarbon phase containing hydrophobic nanoparticles by another non-wetting aqueous phase will also generate nanoparticle-stabilized emulsion symptoms. This research reveals that compared to the control case (no nanoparticles), nanoparticles have the greatest effect on drainage type displacement (hydrocarbon invasion) with pressure drop reaching up to 500 % or even greater compared to the initial pressure drop observed at the start of the displacement. It also shows that those particles have little effect on imbibition displacement (aqueous phase invasion). This was found to be true for both oil-wet and water-wet despite the fact that fluids are configured differently at the pore-scale level. As for a more viscous hydrocarbon phase (tetradecane), the observed effects are generally lessened. As for secondary drainage displacement, initial trapping and the distribution of the hydrocarbon phase has also reduced the severity of the emulsion generation process. Based on the previous findings, an attempt to test the hypothesis of displacing hydrophobic nanoparticle dispersion by an aqueous brine solution under oil-wet condition was inconclusive due to the difficulty of maintaining stable hydrocarbon-nanoparticle dispersion. The displacement profile for all imbibition cases showed no significant differences between nanoparticle case and control case. Yet, we observe that nanoparticles have caused a reduction in the residual hydrocarbon saturation. This reduction was slightly greater for water-wet core compared to oil-wet. For these results I conclude that Haines jump and Roof snap-off may be one of the primary processes responsible to generate nanoparticle-stabilized emulsion during drainage displacement. However, observing emulsion symptoms during secondary drainage in oil-wet cores suggest either a) exact configuration is not important or b) possible alteration in the rock wettability by nanoparticles to produce the same configuration. The viscosity results suggest that nanoparticle effects have largely altered the conformance of the displacement. The presence of ethylene glycol and/or other coating chemicals used to maintain stability of nanoparticle dispersion may have caused the reduction of hydrocarbon phase residual saturation during all imbibition type displacement.Item Wettability alteration in high temperature and high salinity carbonate reservoirs(2011-08) Sharma, Gaurav, M.S. in Engineering; Mohanty, Kishore Kumar; Pope, Gary A.The goal of this work is to change the wettability of a carbonate rock from oil wet-mixed-wet towards water-wet at high temperature and high salinity. Only simple surfactant systems (single surfactant, dual surfactants) in dilute concentration were tried for this purpose. It was thought that the change in wettability would help to recover more oil during secondary surfactant flood as compared to regular waterflood. Three types of surfactants, anionic, non-ionic and cationic surfactants in dilute concentrations (<0.2 wt%) were used. Initial surfactant screening was done on the basis of aqueous stability at these harsh conditions. Contact angle experiments on aged calcite plates were done to narrow down the list of surfactants and spontaneous imbibition experiments were conducted on field cores for promising surfactants. Secondary waterflooding was conducted in cores with and without the wettability altering surfactants. It was observed that barring a few surfactants, most were aqueous unstable by themselves at these harsh conditions. Dual surfactant systems, a mixture of a non-ionic and a cationic surfactant increased the aqueous stability of the non-ionic surfactants. One of the dual surfactant system, a mixture of Tergitol NP-10 and Dodecyl trimethyl ammonium bromide, proved very effective for wettability alteration and could recover 70-80% of OOIP during spontaneous imbibition. Secondary waterflooding with the wettability altering surfactant (without alkali or polymer) increased the oil recovery over the waterflooding without the surfactants (from 29% to 40% OOIP). Surfactant adsorption calculated during the coreflood showed an adsorption of 0.24 mg NP-10/gm of rock and 0.20 mg DTAB/gm of rock. A waterflood done after the surfactant flood revealed change in the relative permeability before and after the surfactant flood suggesting change in wettability towards water-wet.