Align with current dynamic technology development, waterflooding techniques have been improved and optimized to have better oil recovery performance. In addition the latest worldwide industries innovation trends are miniaturization and nanotechnology materials such as nanoparticles. Hence one of the ideas is using nanoparticles to assist waterflood performance. However it is crucial to have a clear depiction of some parameters that may influences displacement process. The focus of this study is to investigate the effects of some parameters influencing oil recovery process due to nanoparticles such as particle size, rock permeability, initial rock wettability, injection rate and temperature. This study is part of our ongoing research in developing nanofluids for future or alternative enhanced oil recovery (Nano-EOR) method. Three different sizes of hydrophilic silica nanoparticles with single particle diameter range from 7 to 40 nm were employed and have been characterized under scanning electron microscope (SEM). Nanofluids were synthesized using 0.05 wt.% nanoparticles that dispersed into synthetic brine (NaCl 3 wt.% ~ 30,000 ppm). The contact angle variation due to nanoparticles size was also measured at room condition. Coreflood experiment has been conducted using 26 Berea sandstone cores to evaluate the effect of those parameters above on oil recovery due to Nano-EOR. The cores permeability was in range from 5 to 450 mD. To study the effect of initial rock wettability on oil recovery due to Nano-EOR, original core wettability has been changed with aging process from water-wet to intermediate and oil-wet respectively. Temperature was also studied in range 25-80 °C to fulfill the possibility of applying Nano-EOR at reservoir temperature. The coreflood testing was repeated for each case to have consistency result. The processes and results are outlined and also further detailed in the paper to bring knowledge about nanoparticles flooding as a future promising EOR method.

In a past decade, various nanoparticle experiments have been initiated for improved/enhanced oil recovery (IOR/EOR) project by worldwide petroleum researchers and it has been recognized as a promising agent for IOR/EOR at laboratory scale. A hydrophilic silica nanoparticle with average primary particle size of 7 nm was chosen for this study. Nanofluid was synthesized using synthetic reservoir brine. In this paper, experimental study has been performed to evaluate oil recovery using nanofluid injection onto several water-wet Berea sandstone core plugs. Three injection schemes associated with nanofluid were performed: 1) nanofluid flooding as secondary recovery process, 2) brine flooding as tertiary recovery processs (following after nanofluid flooding at residual oil saturation), and 3) nanofluid flooding as tertiary recovery process. Interfacial tension (IFT) has been measured using spinning drop method between synthetic oil and brine/nanofluid. It observed that IFT decreased when nanoparticles were introduced to brine. Compare with brine flooding as secondary recovery, nanofluid flooding almost reach 8% higher oil recovery (% of original oil in place/OOIP) onto Berea cores. The nanofluid also reduced residual oil saturation in the range of 2-13% of pore volume (PV) at core scale. In injection scheme 2, additional oil recovery from brine flooding only reached less than 1% of OOIP. As tertiary recovery, nanofluid flooding reached additional oil recovery of almost 2% of OOIP. The IFT reduction may become a part of recovery mechanism in our studies. The essential results from our experiments showed that nanofluid flooding have more potential in improving oil recovery as secondary recovery compared to tertiary recovery.

Sequestration of carbon dioxide in a saline aquifer is currently being evaluated as a possible way to handle carbon dioxide emitted from a coal-fuelled power plant in Svalbard. The chosen reservoir is a 300 m thick, laterally extensive, shallow marine formation of late Triassic-mid Jurassic age, located below Longyearbyen in Svalbard. The reservoir consists of 300 m of alternating sandstone and shale and is capped by 400 meter shale.Experimental and numerical studies have been performed to evaluate CO 2 storage capacity and long term behaviour of the injected CO 2 in rock pore space. Laboratory core flooding experiments were conducted during which air was injected into brine saturated cores at standard conditions. Analysis of the results shows that the permeability is generally less than 2 millidarcies and the capillary entry pressure is high. For most samples, no gas flow was detected in the presence of brine, when employing a reasonable pressure gradient. This poses a serious challenge with respect to achieving viable levels of injectivity and injection pressure.A conceptual numerical simulation of CO 2 injection into a segment of the planned reservoir was performed using commercial reservoir simulation software and available petrophysical data. The results show that injection using vertical wells yields the same injectivity but more increases in field pressure compare to injection through horizontal wells. In order to keep induced pressure below top-seal fracturation pressure and preventing the fast propagation and migration of CO 2 plume, slow injection through several horizontal wells into the lower part of the "high" permeability beds appears to offer the best solution.The high capillary pressure causes slow migration of the CO 2 plume, and regional groundwater flow provides fresh brine for CO 2 dissolution. In our simulations, half of the CO 2 was dissolved in brine and the other half dispersed within a radius of 1000 meter from the wells after 4000 years. Dissolution of CO 2 in brine and lateral convective mixing from CO 2 saturated brine to surrounding fresh brine are the dominant mechanisms for CO 2 storage in this specific site and this guarantees that the CO 2 plume will be stationary for thousands of years.

Nanotechnology has contributed to the technological advances in various industries, such as medicine, electronics, biomaterials and renewable energy production over the last decade. Recently, a renewed interest arises in the application of nanotechnology for the upstream petroleum industry; such as exploration, drilling, production and distribution. In particular, adding nanoparticles to fluids may drastically benefit enhanced oil recovery and improve well drilling, such as changing the properties of the fluid, wettability alternation of rocks, advanced drag reduction, strengthening sand consolidation, reducing the interfacial tension and increasing the mobility of the capillary-trapped oil. In this study, we focus on the fundamental understanding of the role of nanoparticles on the oil-water binary mixture in a confined nanochannel. A series of computational experiments of oil-water-nanoparticle flow behaviour in confined clay nanochannels are carried out by molecular dynamics simulations. Three sizes of nanochannels and different numbers of nanoparticles are considered. The results show that the pressure to drive the oil-water binary mixture through a periodic confined channel increases dramatically with the reduction of the channel size. In the absence of nanoparticles the pressure increases with the propelled displacement. Interestingly, an opposite behavior is observed in the oil-water system mixed with a small amount of nanoparticles: the pressure decreases with the increase of the displacement. The findings from molecular dynamics simulations may elucidate the role of nanoparticles on the transport of oil in nanoscale porous media, although the exact mechanisms remain to be further explored.

Sequestration of carbon dioxide in a saline aquifer into shallow marine formation of Jurassic sandstones in Svalbard has been studied on unfractured cores and by using a simplified set of geological boundary conditions. In this paper, the feasibility of storing CO 2 in a fracture and matrix system in a low permeable formation is studied by performing a series of laboratory experiments under different stress conditions. Laboratory core flooding experiments were conducted on two alternative fractured and unfractured cores. Water and nitrogen were injected into brine saturated cores at the reservoir conditions. The result shows that core plugs are very tight and the liquid permeability even for fractured core is less than 1 millidarcy. Under increased acting stress from 10 to 180 bar, the effective permeability of fractured core is reduced by 73 percent and fluid flow occurs through both fracture and matrix.A conceptual, generic and simple 3D numerical model using commercial reservoir simulation software and available petrophysical data was used to study the CO 2 injection through fracture at different overburden pressure. The effect of different overburden pressures were applied by using respective permeabilities in simulation model. Mean pressure along the cores was used to match simulation predictions with experiments results. The result shows that even though the system is water-wet, and matrix has a very high capillary pressure, CO 2 flows through both fracture and matrix. The amount of CO 2 that flows through the fracture is high and is reduced by increasing overburden pressure. The quantity of dissolved CO 2 in brine phase reduces by decreasing overburden pressure and increasing permeability. The faster the CO 2 is flowing through the fracture less time is available for CO 2 to trap as residual phase and dissolve in brine. In dipping fractured saline aquifer, CO 2 plume movement in updip direction is accelerated by decreased overburden pressure and increased permeability.