New technologies are emerging oil industry to afford the need for increasing oil recovery from oilfields, one of which is Nanotechnology. This paper experimentally investigates a special type of Nanoparticles named Polysilicon ones which are very promising materials to be used in near future for enhanced oil recovery. There are three types of Polysilicon Nanoparticles which can be used according the reservoir wettability conditions. In this paper, hydrophobic and lipophilic polysilicon (HLP) and naturally wet polysilicon (NWP) are investigated as EOR agents in water-wet sandstone rocks. These two Nanoparticles recover additional oil through major mechanisms of interfacial tension reduction and wettability alteration. The impact of these two Nanoparticle types on water-oil interfacial tension and the contact angle developed between oil and the rock surface in presence of water phase were investigated. Then, several coreflood experiments were conducted to study their impacts directly on recoveries. Furthermore, optimum pore-volume injection of each Nano-fluid was determined according the pressure drop across the core samples. The results show a change toward less water-wet condition and a drastic decrease in oil-water interfacial tension from 26.3 mN/m to 1.75 mN/m and 2.55 mN/m after application of HLP and NWP Nano-fluids respectively. As a result, oil recoveries increase by 32.2% and 28.57% when a 4 gr/lit concentration of HLP and NWP Nano fluids are injected into the core samples respectively. According the differential pressure data, two and three pore-volume injections of NWP and HLP Nano-fluids are the best injection volumes respectively. Finally, HLP and NWP Nanoparticles improve oil recovery without inducing any formation damage according the oil recovery and pressure drop data.

In this paper, oil recovery and permeability reduction of a tight sandstone core sample in miscible CO 2 flooding processes due to asphaltene deposition were studied using an Iranian bottom hole live oil sample in order to distinguish between the mechanical plugging and adsorption mechanisms of asphaltene involved in the interfacial interaction of the asphaltene/ mineral rock system. A novel experimental method was designed and proposed to measure the amount of deposited asphaltene due to different mechanisms using the cyclohexane or toluene reverse flooding and spectrophotometer. In this work, the bottom hole live oil sample was injected first to a long core and then CO 2 injection was performed which is close to reservoir conditions, whereas in the majority of previous works, the mixture of recombined oil (mixture dead oil and associated gas) and CO 2 was injected in a short core sample which is far from reservoir conditions. Then, the cyclohexane and toluene reverse flooding was performed, and the amount of deposited asphaltene was measured by spectrophotometer. It was found that by increasing the flow rate of injected CO 2 , pressure drop across the core increased significantly and then decreased. These significant increases in pressure drops indicate more asphaltene deposition and consequently more permeability reduction. Also, it has been found that 20−40% permeability reduction by asphaltene deposition was caused by adsorption mechanism in the CO 2 flooding process during a slow process, whereas 60−80% of formation damage is due to a mechanical plugging mechanism and takes place in a short time. Also, a modified model based on multilayer adsorption theory and four material balance equations (oil, asphaltene, light components, and water phase) was developed to account asphaltene adsorption in core sample during CO 2 flooding and the model was verified using experimental data obtained in this work. The results show that the developed model based on multilayer adsorption theory and four material balance equations is more accurate than those obtained from the monolayer adsorption theory and two material balance equations (the existing models) and is in good agreement with the experimental data reported in this work.

Regarding the most reservoirs around the world are experiencing their second half of life, the need for an appropriate EOR method utilizing efficient new technologies gets more important. Nanotechnology is an advanced technology finding its place in EOR processes as it provides a high potential for oil and gas recovery. In this study, a special type of polysilicon nanoparticle (HLP, Hydrophobic and Lipophilic Polysilicon) is investigated as an EOR agent during different water injection scenarios. The water-wet sandstone core samples are employed. Injection of HLP nanoparticle dispersed in a carrier fluid can improve oil recovery through two mechanisms: reduction of interfacial tension and wettability alteration. Reduction of interfacial tension improves pore-scale displacement efficiency. In addition, wettability alteration towards less water-wet condition provides an ideal wetting state increasing oil recovery. Three scenarios of HLP nanofluid injections are applied. First, the nanofluid is injected after waterflooding at ultimate oil saturation. Second, 3 porevolume water injection is applied after the sequence of water and HLP nanofluid injections. Third, HLP nanofluid is injected from beginning. HLP nanofluid application lowers the oil-water interfacial tension by a factor of ten as well as changing the contact angle from 123° to 99°indicating less water wet condition. The experienced oil recoveries and pressure drops during the experiments are reported for each scenario. In all scenarios, the most of oil recovered through the first injected pore volume. According to oil recoveries, nanofluid injection from the beginning can enhance oil production considerably in compare to the other ones. Moreover, pressure drop data indicate severe permeability impairment after three pore-volume injection of nanofluids. Experimentally, nanotechnology has proved its potential to enhance oil recovery however many aspects are still in progress to be known.

In this work, a new model based on the multilayer adsorption kinetic mechanism and four material balance equations for oil, asphaltene, gas, and water phase has been developed to account for asphaltene deposition in porous media under dynamic conditions and the model was verified using experimental data obtained in this work and also with those reported in the literature. The results showed that the developed model based on multilayer adsorption kinetic mechanism can correlate more accurately the oil flooding experimental data in comparison to the previous models based on the mechanical plugging mechanism, in particular in carbonate core samples. Also, a series of experiments was carried to determine the permeability reduction of carbonate, sandstone, and dolomite core samples due to asphaltene deposition using an Iranian bottom hole live oil sample which is close to reservoir conditions in order to study the effect of different parameters on asphaltene deposition mechanisms during dynamic conditions in porous media. The performance of the effective parameters of porous media on asphaltene deposition such as mineral composition and morphology of surface was also studied using X-ray, elemental analysis, and scanning electron micrographs (SEMs). It was found that an increase of the iron content of core sample leads to a less permeability damage and an increase of the calcium content of core sample leads to an increase of the permeability damage during natural depletion due to asphaltene deposition. SEMs of carbonate core sample showed the formation of large clusters of asphaltene with characteristic sizes that greatly exceed the monolayer deposition characteristic size. Also, a novel experimental method was designed and proposed to distinguish between the mechanical plugging and adsorption mechanisms of asphaltene using the cyclohexane or toluene reverse flooding and it has been found that 60−82% permeability reduction by asphaltene deposition was caused by mechanical plugging mechanism during a fast process, whereas 18−40% of formation damage is due to an adsorption mechanism that takes place in a longer time.

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