EOR using alumina nanofluids increases rock wettability

April 2, 2018
Researchers ran a series of core flooding experiments in a Western Desert field in Egypt to study how different alumina nanofluid concentrations affect brine displacement, relative permeability curves, rock wettability, and ultimate estimated recovery.

Sayed Gomaa

Al-Azhar University


Adel Salem

Suez University


Mohamed Hassan

Belayim Petroleum Co.


Alumina nanoparticles in a displacing brine alter rock wettability and increase the ultimate recovery factor in Egypt's Western Desert, providing a new method of enhanced oil recovery (EOR).

Nanoparticles are believed to have great potential in wettability alternation of cores, improving recovery factors. Researchers ran a series of core flooding experiments to determine the effect of different concentrations of aluminum oxide (alumina, Al2O3) nanoparticles.

An ultimate recovery factor of 81.13% at 10 g /l. alumina nanofluid led to a 20.75% oil recovery over what was achieved by water flooding.

Al2O3 changes the wettability of the sandstone rock. After nanofluids are injected into the core sample, it became more water wet. Researchers measured contact angles to determine rock wettability and recovery factors.

Reservoir engineers seek ways to alter the wettability from oil wet to water wet or from water wet to highly water wet in efforts to change total recovery factor. Wettability affects fluid distribution, relative permeability, and flow behavior through porous media. Nanoparticles have great potential for altering rock wettability.

Experimental work

Researchers used a 70,000-ppm brine prepared with NaCl salt. This concentration represents average Egyptian oil field reservoir water salinity. The core samples came from an Egyptian oil field in the Western Desert.

A pycnometer measured the brine and oil density, and a rolling ball viscometer measured viscosity. The bulk volume, pore volume, and porosity were measured using a helium porosimeter and the liquid saturation method. Researchers used a gas permeameter and a liquid permeameter to measure the core permeability.

Researchers fully immersed the core in a beaker containing the prepared brine. The core was placed in a vacuum saturator for 2 hr to ensure full saturation.

Laboratory workers prepared nanofluids, which went into a probe sonicator or a bath sonicator.

Sonication takes 2 hr to guarantee full suspension of nanoparticles in the fluid. During sonication, specific sound waves are forced through a solution, agitating its particles. The resulting disruptions can better mix the solution or accelerate dissolution of solids inside the liquid.

Sound waves cross alternating high-pressure and low-pressure regions. Frequency of the sound waves measures how often the particles vibrate. Sonication of nanoparticles is most effective at ultrasonic frequencies above 20 kHz.

An increased frequency leads to better agitation and suspension of the nanoparticles. Researchers used a probe sonicator with a frequency of 50 kHz. It worked with an amplitude range of 30-90%.

Fig. 1 shows a schematic of the flooding apparatus. The core is placed in the core flooding device. Oil is injected into the core under high-pressure differential, enabling oil to replace brine. This process stops when no more brine exits the core. At this point, the production water cut is zero.

A low pumping rate during flooding adheres to Darcy's law. Volumes of produced oil and brine are measured, and their flow rates calculated. The pressure difference and process time are also monitored at each step.

Researchers use these parameters to calculate and plot the recovery factor and relative permeability curves.

The core represents an oil reservoir. Any remaining brine inside the core is considered connate water. The volume of brine produced is calculated through graded tubes and considered to be the volume of oil in place.

Researchers calculate the amount of pore volume (PV) remaining, considered to be the interstitial water volume, using the data to determine critical water saturation and oil saturation.

Nanoparticles identification

The Egyptian Petroleum Research Institute (EPRI) prepared the alumina particles. The prepared alumina is a nano-sized highly crystalline alpha-type alumina powder synthesized by microwave combustion at 900 w for 5 min with a metal-fuel molar ratio of 1:3.

A high-resolution transmission electron microscopy (HRTEM) test sized the alumina nanoparticles. An X-ray diffraction test on very fine particles with a spherical shape showed the presence of a highly crystalline phase.

Injection of an Al2O3 nanofluid inside an oil reservoir leads to decreased residual oil saturation, increased oil production, and increased overall ultimate recovery from the field.

The nanofluid injection occurs in the tertiary recovery phase after the water flood. Researchers injected multiple concentrations of nanofluid into the core plug: 3 g/l., 5 g/l., 7 g/l., and 10 g/l.

Lab workers cleaned the core between tests by removing it from the flooding device and soaking it overnight in a solvent. The core was heated in an oven to evaporate all fluids before the next experiment.

The experimental procedure follows:

• Place the saturated core plug inside the core-flooding device.

• Apply confining pressure until all injected fluid passes through the core to ensure there are no leaks in the device. A hydraulic pump fixed at 500 psi creates the confining pressure.

• Place the oil inside the core-flooding device and inject pressure on the oil inside the rock sample.

• Transfer the brine solution from the core sample to a graduated tube.

• Calculate the brine solution volume using the graduated tube. The brine represents the oil in place.

• Calculate the connate water saturation.

• Continue the experiment for 2 hr to ensure no additional brine solution can be removed from the core.


Researchers determined initial volume of oil in place was 10.6 cc, oil saturation was 67.67%, and the connate water saturation was 32.33%.

In the base run, the core sample was water flooded (WF) with no nanofluid. Researchers started by injecting 0.2 PV and periodically monitored the recovery with increased injections going up to 5 PV.

The oil recovery factor increased as the injected pore volume increased. The water injection continued until no more oil was produced and all output fluid was water or up to the economic limit. The recovery factor was 60.38% of original oil in place.

In the nano alumina flooding, the concentration of the Al2O3 nanofluid is 3 g/l. of brine solution. This represents about 3,000 ppm or 0.3 wt %, one of the most commonly used concentrations in nanoparticle research.

Researchers prepared the alumina nanofluid using 0.15 g of alumina nanoparticles, which were added to 50 ml brine inside a beaker. They set a sonicator inside the beaker to an amplitude of 50% with one pulse on and one pulse off. The sonication process lasted until no nanoparticles precipitated at the beaker bottom.

The nanofluids went inside the vessel while the vessel was placed on a magnetic stirrer and a magnet placed inside the vessel. The vessel was closed properly to ensure all the pressure was used to push the fluid inside the rock core sample.

Researchers put 0.2 PV inside the vessel under constant pressure to inject the alumina nanofluid inside the rock sample. The amount of water produced, oil produced, time of production, and pressure were determined and recorded for additional calculations.

This same procedure was repeated with PV of 0.4, 0.6, 0.8, and 1.0. Results were collected to calculate water cut, the amount of residual oil, the incremental oil recovery, and the ultimate oil recovery.

Maximum recovery factor with 3 g/l. of alumina nanofluid was 74.38%, a 14% higher recovery factor than the water flooding base run.

The relative permeability curve indicates increased wettability of the rock. The point of intersection for the nanofluids test shifted toward water wet. This meant a better mobility ratio and increased estimated ultimate recovery (EUR). The point of intersection was 72.5% water saturation vs 67.5% with water flooding.

In a 5g/l. concentration alumina nanofluid experiment, the recovery factor was 74.58%, up 0.71% from the 3 g/l. test. The 5 g/l. test increased the recovery factor by 14.71% over the water-flooding base run.

Relative permeability's intersection point moved to about 73.5% water saturation, meaning the core become more water wet with 5 g/l. than with 3 g/l, indicating a better mobility ratio and EUR.

The 7 g/l.-concentration alumina nanofluid experiment showed a 76.13% recovery factor, marking a 1.04% incremental recovery from the 5 g/l. run and running about 15.75% higher than the water-flooding base run.

Relative permeability showed an increasing wettability of the rock sample. The point of intersection for the 7 g/l. concentration was 75.5% water saturation.

Fig. 2 shows results from testing a 10 g/l. concentration, finding a maximum recovery factor of 81.13%, 5% higher than the previous case and about 20.75% higher than the water-flooding base run. The relative permeability curve shows rock wettability moved toward the water-wet region. The point of intersection was 79% water saturation.

Fig. 3 shows the 15 g/l. concentration experiment yielding the lowest recovery factor. The intersection point of the relative permeability curve also was lower than the experiment with a 10 g/l. concentration. The 15 g/l. intersection point decreased to 66.64% water saturation, less than the water flooding base run. Researchers concluded that fluid containing high concentrations of nanoparticles can cause blockage of the pores, decreasing oil production.

Fig. 4 compares the recovery factors achieved by using different alumina nanofluid concentrations.

Wettability changes

Ultimate recovery and relative permeabilities of a reservoir hinge upon the wetting behavior of the rock, which can be water wet or oil wet. An adjustment to the wettability of a reservoir can achieve higher production.

Researchers used a high-resolution camera to measure the contact angle at different concentrations from 0 g/l. to 10 g/l. The table shows that as the concentration increases, the contact angle increases, a change in wettability toward water wet.

The contact angle is the angle, conventionally measured through the liquid, at which a liquid-vapor interface meets a solid surface. It quantifies the wettability of a solid surface by a liquid.

Results confirm the relative permeability curves findings and the intersection point findings. The wettability increase explains the improved incremental recovery factor by alumina nanofluid over conventional water flooding.

The intersection point on the relative permeability curve indicates the degree of rock wettability. Fig. 5 shows the intersection point corresponding to a water saturation higher than 50%, a water-wet rock. The nanofluid concentrations, except for 15 g/l., made the rock more water wet, increasing the recovery factor above that of conventional water flooding.


The authors thank the British University in Egypt, Future University in Egypt, and the Egyptian Petroleum Research Institute for providing research equipment and core plugs.


Li, S., Genys, M., Wang, K., and Torseter, O., "Experimental Study of Wettability Alteration during Nanofluid Enhanced Oil Recovery Process and Its Effect on Oil Recovery," Society of Petroleum Enginers (SPE) Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, Sept. 14-16, 2015.

Ragab, A., and Salem, M., "Unlocking Reservoir Potential using Robust Hybrid Nanoparticles Designed for Future Enhanced Oil Recovery," Mediterranean Offshore Conference & Exhibition, Alexandia, Egypt, Apr. 19-21, 2016.

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Torsater, O., Li, S., and Hendraningrat, L., "A Coreflood Investigation of Nanofluid Enhanced Oil Recovery in Low-Medium Permeability Berea Sandstone," SPE International Symposium on Oilfield Chemistry, The Woodlands, Tex., Apr. 8, 2013.

The authors

Sayed Gomaa ([email protected])is an associate professor of petroleum reservoir engineering at Al-Azhar University and The British University in Egypt. He holds a BSc (1999) and MSc in petroleum engineering (2005) from Al-Azhar University and PhD (2010) in petroleum engineering from Azerbaijan State Oil Academy.

Adel Moh. Salem Ragab ([email protected]) is an associate professor and head of the petroleum engineering department at Suez University. He obtained a PhD (2008) in petroleum engineering from Leoben University, Austria. He also earned a BS and MS from Suez Canal University, Egypt. Previously, Adel was assistant professor at American University in Cairo for 4 years, Future University in Egypt for 2 years, and Suez Canal University for 3 years. He has published more than 45 papers on EOR, characterization of formation damage, nanotechnology of EOR, and smart drilling fluids, oil shale, well testing, and radial drilling.

Mohamed Hassan ([email protected]) is a petroleum engineer for Belayim Petroleum Co. He holds a BS (2016) in petroleum engineering from British University in Egypt.