Nanoparticles have been speculated as good in-situ agents for solving reservoir engineering problems. Some selected types of nanoparticles that are likely to be used include oxides of Aluminium, Zinc, Magnesium, Iron, Zirconium, Nickel, Tin and Silicon. It is therefore imperative to find out the effect of these nanoparticle oxides on oil recovery since this is the primary objective of the oil industry. These nanoparticles were used to conduct EOR experiments under surface conditions. Distilled water, brine, ethanol and diesel were used as the dispersing media for the nanoparticles. Two sets of experiments were conducted. The first involved displacing the injected oil with the nanofluids. In the second case, the sands were soaked in nanofluids for 60 days before oil was injected into the system and displaced with low salinity brine. Generally, using nanofluids to displace injected oil produced a better result. Results obtained from the experiments indicate that Aluminium oxide and Silicon oxide are good agents for EOR. Aluminium oxide nanoparticle is good for oil recovery when used with distilled water and brine as dispersing agents. For the use of ethanol, Silane treated Silicon oxide gave the highest recovery in all the conducted experiments while hydrophobic Silicon oxide in ethanol also yielded good results. Aluminium oxide reduces oil viscosity while Silicon oxide changes rock wettability in addition to reduction of interfacial tension between oil and water caused by the presence of ethanol. For the use of diesel as a nanoparticle dispersing fluid, because diesel and crude oil are miscible, the actual crude oil recovery cannot be determined but the overall result with Aluminium, Nickel and Iron oxides appears good. Magnesium oxide and Zinc oxide dispersed in distilled water and brine cause permeability problems. Generally, distilled water lowers oil recovery. This emphasizes the significant role a fluid plays as a nanoparticle dispersing agent in the formation because it can contribute positively or negatively in oil recovery apart from the effect of the nanoparticles.

This paper is aimed at studying the ability of three different polysilicon nanoparticles (PSNP) to enhance oil recovery. Changing rock wettability is the target because wettability is a primary factor that affects recovery efficiency. The experiments conducted centered on laboratory coreflooding using two kinds of oil, brine and polysilicon nanofluids on water wet rocks obtained from the Niger Delta. The three kinds of PSNP used for this study were lipophobic and hydrophilic PSNP (LHPN), hydrophobic and lipophilic PSNP (HLPN) and neutrally wet PSNP (NWPN).The results obtained indicate that NWPN and HLPN are good enhanced oil recovery (EOR) agents in water wet formations. Two mechanisms through which oil recovery is enhanced using NWPN and HLPN are change of rock wettability and reduction of interfacial tension by the improved quality of ethanol, the dispersing agent. Thus NWPN and HLPN dispersed in ethanol are recommended for use in EOR for water wet formations. LHPN which make already water wet rocks strongly water wet yield poor recovery factors indicating that its use for EOR should be restricted to oil wet formations.

Gas recovery factor from water drive gas reservoirs is very low compared to recovery made from depletion drive gas reservoirs. Other problems associated with gas recovery from water drive mechanism include high residual gas saturation in the water invaded zone of the reservoir, high volume of produced water, abandonment at high reservoir pressures and high possibility of hydrate formation in pipe lines. The use of carbon dioxide (CO 2 ) in displacing natural gas from volumetric gas reservoirs has been studied, practised and is successful. In this paper, it is proposed that extending this practice to gas reservoirs under strong water drive mechanism can improve recovery and control water influx.CO 2 is denser than natural gas and water is denser than CO 2 . The different densities of these fluids can be taken advantage of to boost natural gas recovery from water drive gas reservoirs. The continuous CO 2 injection process at the gas water (g/w) contact can partially prevent water encroachment into the system. The technique can change the water drive mechanism to full or partial depletion drive where CO 2 will separate the natural gas zone from direct contact with the water zone. Any eventual water invasion into the reservoir affects the CO 2 zone, not the upward moving natural gas zone. This technique was studied by simulation using data from a lean gas reservoir under strong water drive. Two cases were considered. In the first case, which is the reference case, gas production under water drive was allowed for 30years. In the second case, CO 2 was injected at the initial gas water contact for the same number of years. Simulation results showed that water production from the reservoir was drastically reduced to about 60% in the second case because the rate of water influx into the reservoir was controlled. Gas recovery from two producer wells out of three that were considered improved above 10% and gas condensate recovery was improved to about 4% over the period of production that CO 2 was injected.

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