Wettability alteration is an important method to increase oil recovery from oil-wet carbonate reservoirs. Chemical agents like surfactants are known as wettability modifiers in carbonate systems. However, the effectiveness of these agents can be increased by the addition of chemicals such as polymers, ionic materials, and nanoparticles. The impacts of nanoparticles on the wettability of carbonate systems have not been reported yet, and it is still in its infancy. In this work, the effect of ZrO 2 -based nanofluids on the wettability alteration of a carbonate reservoir rock was experimentally studied. Several nanofluids were made composed of ZrO 2 nanoparticles and mixtures of nonionic surfactants. The effect of nanofluids on the wettability of carbonate samples were investigated by measuring the contact angles, and it was shown that designed nanofluids could significantly change the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Scanning electron microscopy (SEM) images and X-ray Diffraction (XRD) data verify adsorption of nanoparticles on the rock and formation of nanotextured surfaces. Moreover, this paper reports the quick imbibitions of ZrO 2 nanofluids into oil-wet core plugs saturated with stock tank oil. The results show that a considerable amount of oil can be quickly recovered by free imbibitions of the nanofluids into the core plugs. A theoretical approach is also presented to explain the wettability alteration by formation of composite nanotextured surfaces.

Asphaltene precipitation causes several problems during crude oil production, transportation, and refinery processes. Therefore, finding an inhibitor to prevent or delay asphaltene precipitation is of paramount importance. In this work, effects of TiO2, ZrO2, and SiO2 fine nanoparticles in organic-based nanofluids have been investigated to study their potential for stabilizing asphaltene particles in oil. To this end, polarized light microscopy has been applied to determine the onset of asphaltene precipitation by titration of dead oil samples from Iranian crude oil reservoirs with n-heptane in the presence of nanofluids. Results show that rutile (TiO2) fine nanoparticles can effectively enhance the asphaltene stability in acidic conditions and act inversely in basic conditions. It was found that the required amount of n-heptane for destabilizing the colloidal asphaltene is considerably higher in presence of TiO2 nanofluids at pH below 4. The FTIR spectroscopy indicates changes in n-heptane insoluble asphaltene when acidic TiO2 nanofluid is used as inhibitor. According to the results obtained by FTIR spectroscopy, TiO2 nanoparticles can enhance the stability of asphaltene nanoaggregates through formation of hydrogen bond at acidic conditions. This is while other materials used in this experiment, as well as the TiO2 nanoparticles in basic conditions, are unable to form any hydrogen bond – hence their incapability to prevent asphaltene precipitation. Dynamic light scattering (DLS) measurements also have been performed to explain the mechanism of asphaltene precipitation in the presence of nanoparticles.

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Underground Gas Storage (UGS) is a means of installing peak shaving capacity during high-demand seasons worldwide. In this work, studies of the UGS were performed on a partially depleted gas reservoir through compositional simulation. Prediction of reservoir fluid phase behavior and history match was done by utilizing detailed reservoir information. The performance of UGS with different scenarios of reservoir depletion, gas injection, and aquifer strength was analyzed. The injection capacity and deliverability of reservoir was set to 350 MMSCF/D (6 months) and 420 MMSCF/D (5 months), respectively. Based on different scenarios and the anticipated target rate, the optimum pressure for converting this reservoir to UGS was found to be about 1600 psia. Also, it was found that if the reservoir is depleted to a lower pressure, it contains insufficient base gas reserve and may not meet the target withdrawal rate. It was found that this problem can be overcome by injecting higher volume of gas in the first cycle. Furthermore, simulation studies showed that an active aquifer can lead to irreversible reservoir shrinkage, increase in water-gas ratio, and pressure rise in reservoir. Another source of pressure rise during the UGS operations is the difference between z-factors of injected and reservoir fluids. It was found that injecting lean gas with high z-factor into a reservoir containing fluid of lower z-factor results in pressure rise at the end of each cycle. At successive cycles, composition of reservoir fluid approaches that of the injected gas because of continual mixing. Theoretically, composition of reservoir fluid will approach to the injected fluid after infinite cycles, provided complete mixing occurs in reservoir. Under these conditions, difference between z-factors of injected and reservoir fluids become smaller, and reservoir pressure stabilizes. Introduction The idea of storing natural gas in underground reservoirs during low consumption seasons to be used in high-demand seasons and meet the peak rates has found worldwide application since 1950s (Katz et al. 1959). Underground Gas Storage (UGS) is a cost effective means of installing peak shaving capacity close to gas consumers. This saves part of substantial development costs required to install a peak shaving capacity at the source, i.e. at the producing gas fields. Especially where small offshore fields are connected to gas infrastructure, large savings can be gained. Such high unit investment fields can thus be developed more economically. The UGS has not only been found interesting as a solution to overcome the energy shortage during winter, but also to keep gas production capacity from processing units and refineries in the summer. The importance of UGS is growing worldwide for both industrial (Power plants, Energy Intensive industries, etc.) and urban applications. The working gas capacity from all UGS reservoir types is estimated to be 365 - 400 × 109 m3 (12.9–14.1×1012SCF) (Chabrelie et al. 2007). This technology plays an increasingly important role in managing production and supply of natural gas in the world.

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