*4.1.2.1 Wettability and IFT alteration*

Wettability is the preferential tendency of one fluid to wet (or to spread) onto a surface [76]. To produce more oil, the wettability of the oil-water-rock system should be shifted from oil-wet to a water-wet or strongly water wet condition. MO-NPs can adsorb onto the rock surface and form a nanotexture, which contributes to wettability alteration [77]. However, these mechanisms are affected by the formation salinity (**Figure 7**).

At a low salt concentration, the activity coefficient of the salt increases in a manner that the salt molecules sit within the oil phase. With the presence of salt at the interface, the excess surface concentration turns positive from which results a low contact angle (**Figure 7a**) and higher IFT (**Figure 7b)**. An oil production scenario in which the salt concentration is large, the salting-out effect seems to prevail [47].

MO-NPs are depleted at the interface and transferred back to oil phase. This breaks the oil-water interface adsorption, hence a high contact angle. The same behavior could be extended when two immiscible liquids (oil and water) meet each

*Advances in Microfluidics and Nanofluids*

**4. Application of MO-NFs to fossil, gas storage and renewable energy**

*C; the nanofluid consists in Si-NP dispersed in a polymer* 

*Influence of gas bubbling on the stability of nanofluid; the nanofluid consists in Si-NP dispersed in a deionized* 

Improved oil recovery (IOR) or enhanced oil recovery (EOR) are two terms used loosely to describe the improvement of oil recovery after both the primary and the secondary stages of oil production become economically unattractive or technically not feasible. In principle, IOR is the general term to designate any implemented means after secondary process that increases considerably the amount of oil recovered. On the hand, EOR defines a specific technique (or a combination

**4.1 Fossil energy and enhanced oil recovery (EOR)**

*(PVOH) solution prepared following two-step approach using CO2 bubbling.*

*Influence of BF on the stability of nanofluid at 25<sup>o</sup>*

of techniques) implemented to decrease the residual oil.

*4.1.1 Tertiary oil recovery*

**138**

**Figure 5.**

**Figure 6.**

*water.*

#### **Figure 7.**

*Influence formation salinity on wettability and IFT alteration. (a) Wettability alteration modified from adapted with permission from [47]. Copyright (2020) American Chemical Society. (b) IFT alteration; this study.*

**Figure 8.** *Influence of type of MO-NPs on IFT alteration.*

other. The molecules at the surface of both of those liquids become unbalanced forces of attraction, which cause the IFT to rise.

Adding MO-NPs could not only reduce the IFT but also the contact angle. For example, it was found adding only 0.25 wt.% of MO-NP to a polymeric BF, the contact angle as well as the IFT between the nanofluid and heavy oil (API 16<sup>o</sup> ) decreases about 50% from its initial value (**Figure 8**).

#### *4.1.2.2 Improve mobility ratio of injected fluids*

The mobility ratio of water to oil is one of the most critical factors to influence water flood efficiency. When mobility is greater than one, it is considered unfavorable as the displacing fluid is more mobile than oil in the porous medium; the slug tends to bypass oil and early breakthrough is experienced at the producers (channeling). At a mobility ratio of less than one, water is less mobile than oil leading to better displacement and recovery of oil.

The mobility ratio can be decreased either by reduction of the viscosity of the resident oil or by increasing that of the nanofluid. As shown in **Figure 9**, increasing the load in MO-NP (SiO2-NP in this experiment) prompted an increase in oil recovery in a waterflooded sandstone.

**141**

**Figure 10.**

*Oil recovery using Si-NPs in contrasted sandstone formations.*

*Nanocomposite and Nanofluids: Towards a Sustainable Carbon Capture, Utilization, and Storage*

The experiments were conducted using light mineral (specific density 0.838,

This is because of the difference in native composition including a low acid number,

Pore channels plugging can be caused by two mechanisms: mechanical entrapment and log-jamming. These mechanisms were evaluated in this study by the injection of Si-NP dispersed in aqueous polymeric solution. Two types of formations were considered including a homogeneous formation with a uniform porosity and a heterogeneous formation with contrasted porosity. The results are shown in

The production in homogeneous formation decreases monotonically with the load in Si-NP, while a reverse trend was observed for a heterogeneous model. In a homogeneous formation, the increase in MO-NP load causes the plugging of pore throats, whose size are smaller than the average size in MO-NP dispersed (log jamming). As the nanofluid travels within the formation, the narrowing of flow area

and the differential pressure led to a velocity increase of the nanofluid.

C) and light crude oil (specific density 0.860 viscosity of

C). It was found a higher production when light mineral oil was used.

*DOI: http://dx.doi.org/10.5772/intechopen.95838*

viscosity of 26 cP at 25o

a high concentration of asphaltene.

*Relationship between MO-NP viscosity and oil recovery factor.*

*4.1.2.3 Pore channels plugging*

9.54 cP at 25<sup>o</sup>

**Figure 9.**

**Figure 10**.

*Nanocomposite and Nanofluids: Towards a Sustainable Carbon Capture, Utilization, and Storage DOI: http://dx.doi.org/10.5772/intechopen.95838*

**Figure 9.** *Relationship between MO-NP viscosity and oil recovery factor.*

The experiments were conducted using light mineral (specific density 0.838, viscosity of 26 cP at 25o C) and light crude oil (specific density 0.860 viscosity of 9.54 cP at 25<sup>o</sup> C). It was found a higher production when light mineral oil was used. This is because of the difference in native composition including a low acid number, a high concentration of asphaltene.

#### *4.1.2.3 Pore channels plugging*

*Advances in Microfluidics and Nanofluids*

**Figure 7.**

**Figure 8.**

*study.*

other. The molecules at the surface of both of those liquids become unbalanced

*Influence formation salinity on wettability and IFT alteration. (a) Wettability alteration modified from adapted with permission from [47]. Copyright (2020) American Chemical Society. (b) IFT alteration; this* 

Adding MO-NPs could not only reduce the IFT but also the contact angle. For example, it was found adding only 0.25 wt.% of MO-NP to a polymeric BF, the contact angle as well as the IFT between the nanofluid and heavy oil (API 16<sup>o</sup>

The mobility ratio of water to oil is one of the most critical factors to influence water flood efficiency. When mobility is greater than one, it is considered unfavorable as the displacing fluid is more mobile than oil in the porous medium; the slug tends to bypass oil and early breakthrough is experienced at the producers (channeling). At a mobility ratio of less than one, water is less mobile than oil leading to

The mobility ratio can be decreased either by reduction of the viscosity of the resident oil or by increasing that of the nanofluid. As shown in **Figure 9**, increasing the load in MO-NP (SiO2-NP in this experiment) prompted an increase in oil

)

forces of attraction, which cause the IFT to rise.

*Influence of type of MO-NPs on IFT alteration.*

*4.1.2.2 Improve mobility ratio of injected fluids*

better displacement and recovery of oil.

recovery in a waterflooded sandstone.

decreases about 50% from its initial value (**Figure 8**).

**140**

Pore channels plugging can be caused by two mechanisms: mechanical entrapment and log-jamming. These mechanisms were evaluated in this study by the injection of Si-NP dispersed in aqueous polymeric solution. Two types of formations were considered including a homogeneous formation with a uniform porosity and a heterogeneous formation with contrasted porosity. The results are shown in **Figure 10**.

The production in homogeneous formation decreases monotonically with the load in Si-NP, while a reverse trend was observed for a heterogeneous model. In a homogeneous formation, the increase in MO-NP load causes the plugging of pore throats, whose size are smaller than the average size in MO-NP dispersed (log jamming). As the nanofluid travels within the formation, the narrowing of flow area and the differential pressure led to a velocity increase of the nanofluid.

**Figure 10.** *Oil recovery using Si-NPs in contrasted sandstone formations.*

The smaller molecules will flow faster than causing accumulation of MO-NP at the entrance of the pore throats. For larger load, there is a possibility of having a plugging at the entrance of the throat due to the size of the nanofluid (mechanical entrapment). For formations with contrasted porosity, the log-jamming or mechanical entrapment could be beneficial.

As the pore is plugged, there is a pressure build in the adjacent pore throat, forcing out the oil trapped in the pore throat or the water to move to a layer with lower porosity. This can be considered as temporary log-jamming. This phenomenon is mainly governed by the concentration and size of NPs, flow rate and the diameters of pore throats (**Figure 11**).

### *4.1.2.4 Preventing asphaltene precipitation*

Asphaltene precipitation can cause severe problems due to the deposition inside the reservoir, at the wellhead, and/or inside the pipelines. However, it is believed MO-NPs have the potential to inhibit the adsorption and thus delay the deposition [78, 79]. The particles, in contact with the asphaltenes molecules can minimize the interactions asphaltene-asphaltene and/or asphaltene-rock leading therefore to a mitigation (**Figure 12**).

In this regard, MO-NPs are suitable candidates because their inherent properties. In this study, asphaltenes were extracted from dead heavy crude oil (API 16o ) as per the procedure discussed by Goual [80]. An asphaltenic solution of 1wt.% was prepared by diluting extracted asphaltenes with toluene. Two set of experiments were conducted at room temperature including porosity impairment (**Figure 13a**) and adsorption on sandstone (**Figure 13b**).

**143**

*Nanocomposite and Nanofluids: Towards a Sustainable Carbon Capture, Utilization, and Storage*

It could be seen that the porosity of the waterflooded sandstone decreases upon injection CO2 (**Figure 13a**). Adding MO-NPs to the same water, the impairment could be improved with lowest obtained for Al-NP. This is so because of the higher adsorption capacity of MO-NPs, which interacts more strongly with the asphaltenes. The influence of MO-NP is noticeable as evidenced by the decrease in adsorption (**Figure 13b**).

*Asphaltene mitigation by addition of different types of MO-NPs dispersed into water. (a) Porosity impairment* 

As of 2018, 70% of the global warming was subsequent to the release of greenhouse gases (GHG) to the atmosphere, with fossil resources contributing to up to 37.1 billion metric tons. The total concentration in carbon dioxide, CO2, in the atmosphere was reported to hit its highest level ever (407 ppm) million. Great efforts should be invested to reduce CO2 concentration to an acceptable value. Carbon dioxide capture, utilization and storage (CCUS) technology of which Carbon capture and storage (CCS) technologies have a potential to reduce CO2 emissions to the atmosphere due to the huge global capacity for underground storage [81]. With 21 large-scale CCS projects operating worldwide, the volume of storable CO2 is estimated to be up to 37 Mtpa. Yet more CCS projects are needed to reach the Paris 2 °C target, which is partly due to the leakage of the stored CO2 through the faults of the formation within which the gas is trapped [82, 83]. A typical CCS project encompasses the capture, the compression and transport, and the injection in the designed formation. The success of a gas storage depends primarily on the trapping mechanisms occurring during CO2 containment. A trapping mechanism refers a process (either physical or chemical), which improves the sequestration of CO2. Among the different known trapping mechanisms, three processes stand out including residual, solubility and mineral trapping [84]. During the residual trapping, CO2, injected at its supercritical state, displaces the fluids as it moves through the porous rock. As CO2 moves upward due to the buoyancy difference, some of the CO2 will be left behind as disconnected droplets

This mechanism, however, is challenged by the faults present the geological formation (cap rock). The fault could crack due to the over-pressurization of the aquifer leading to a leak in CO2 Solubility trapping involves the dissolution of supercritical CO2 in the salty water (brine), which leads to a fluid denser than the native fluids. From the difference in buoyancy, the resulting fluids force CO2 to sink at the bottom of formation over time. The problem, in here, is that not only the solubility of CO2 in brine is low, but it reaches quickly its saturation causing thereby an over

*DOI: http://dx.doi.org/10.5772/intechopen.95838*

**Figure 13.**

**4.2 Application of MO-NFs to CO2 Sequestration**

*after CO2 injection. (b) Static adsorption after CO2 injection.*

within the pore throats, which are immobile.

pressurization of the aquifer.

**Figure 12.**

*Conceptual approach of asphaltene inhibition during CO2 injection.*

*Nanocomposite and Nanofluids: Towards a Sustainable Carbon Capture, Utilization, and Storage DOI: http://dx.doi.org/10.5772/intechopen.95838*

**Figure 13.**

*Advances in Microfluidics and Nanofluids*

of pore throats (**Figure 11**).

mitigation (**Figure 12**).

mechanical entrapment could be beneficial.

*4.1.2.4 Preventing asphaltene precipitation*

and adsorption on sandstone (**Figure 13b**).

The smaller molecules will flow faster than causing accumulation of MO-NP at the entrance of the pore throats. For larger load, there is a possibility of having a plugging at the entrance of the throat due to the size of the nanofluid (mechanical entrapment). For formations with contrasted porosity, the log-jamming or

As the pore is plugged, there is a pressure build in the adjacent pore throat, forcing out the oil trapped in the pore throat or the water to move to a layer with lower porosity. This can be considered as temporary log-jamming. This phenomenon is mainly governed by the concentration and size of NPs, flow rate and the diameters

Asphaltene precipitation can cause severe problems due to the deposition inside the reservoir, at the wellhead, and/or inside the pipelines. However, it is believed MO-NPs have the potential to inhibit the adsorption and thus delay the deposition [78, 79]. The particles, in contact with the asphaltenes molecules can minimize the interactions asphaltene-asphaltene and/or asphaltene-rock leading therefore to a

In this regard, MO-NPs are suitable candidates because their inherent properties. In this study, asphaltenes were extracted from dead heavy crude oil (API 16o

as per the procedure discussed by Goual [80]. An asphaltenic solution of 1wt.% was prepared by diluting extracted asphaltenes with toluene. Two set of experiments were conducted at room temperature including porosity impairment (**Figure 13a**)

*Relationship between the displacement efficiency, porosity impairment and type of MO-NPs.*

*Conceptual approach of asphaltene inhibition during CO2 injection.*

)

**142**

**Figure 12.**

**Figure 11.**

*Asphaltene mitigation by addition of different types of MO-NPs dispersed into water. (a) Porosity impairment after CO2 injection. (b) Static adsorption after CO2 injection.*

It could be seen that the porosity of the waterflooded sandstone decreases upon injection CO2 (**Figure 13a**). Adding MO-NPs to the same water, the impairment could be improved with lowest obtained for Al-NP. This is so because of the higher adsorption capacity of MO-NPs, which interacts more strongly with the asphaltenes. The influence of MO-NP is noticeable as evidenced by the decrease in adsorption (**Figure 13b**).
