Surfactants Flooding

#### **Chapter 5**

## An Overview of Natural Surfactant Application for Enhanced Oil Recovery

*Afeez Gbadamosi, Adeyinka Yusuff, Augustine Agi and Jeffrey Oseh*

#### **Abstract**

Surfactant flooding is an enhanced oil recovery (EOR) method that recovers residual and capillary trapped oil by improving pore scale displacement efficiency. Due to toxicity and high cost of conventional surfactant, recent trend involves the use of natural surfactant for EOR. Natural surfactants are benign and biodegradable as they are derived from plant leaves and oil extracts. Herein, a synopsis of recent trend in the incorporation of newly devised natural surfactant for EOR was reviewed. Experimental results show that the surfactants exhibited sterling properties desired for EOR such as lower adsorption, interfacial tension (IFT) reduction, stable emulsion, and wettability alteration of sandstone and carbonate rocks. Overall, natural surfactants are suitable replacement for conventional surfactant. Nonetheless, an accurate modeling and pilot scale studies of natural surfactants remain obscure in literature.

**Keywords:** surfactant, natural surfactant, biosurfactant, enhanced oil recovery, wettability, interfacial tension

#### **1. Introduction**

Global demand for oil and gas continues to increase despite the recent development in other sources of energy. The production of oil and gas is in stages. Firstly, hydrocarbons are produced from reservoir deposit due to pressure reduction in the reservoir. Thereafter, waterflooding is performed to push more oil towards the production well. Substantial amount of oil is left in the reservoir as bypassed and/or residual oil after the application of primary and secondary recovery techniques. This is adduced to viscous fingering phenomenon as the injected waterflood creates a path of least resistance to the production well. Hence, several enhanced oil recovery (EOR) methods have been devised to recover additional oil from the reservoir [1]. **Figure 1** depicts the classification of EOR processes.

#### **Figure 1.**

*Enhanced oil recovery process classification [2].*

The EOR methods are broadly categorized into thermal and non-thermal EOR methods [3]. Thermal EOR are majorly used for the recovery of heavy oil, extra-heavy oil, and tar sands in the reservoir. Several thermal injections have been explored and exploited to improve recovery of high viscosity oils. These include cyclic steam stimulation, steam flooding, steam-assisted gravity drainage, and *in-situ* combustion. The mechanism of thermal EOR is to use high temperature to reduce the high viscosity and consequently improve the mobility of the oil towards the production well. Despite the success recorded for the field application of thermal EOR techniques during field application, they are deemed unsuitable for reservoir with huge depth and thin pay zones. Besides, they have high energy consumption, and large CO2 emissions, thereby, increasing the environmental and economic costs of application [4]. Thus, non-thermal EOR methods have recently received prodigious attention.

The non-thermal EOR methods are gas EOR, microbial EOR and chemical EOR [5, 6]. Gas EOR methods involves the injection of miscible, immiscible, or inert gases into the reservoir to improve recovery factor. In addition to improving recovery factor, the use of gas injection also aids sequestration of gas in subsurface geologic formations. The mechanism of gas flooding includes the mass transfer of components between the oil and injected gas, swelling and viscosity reduction. The application of gas flooding is limited for high viscosity oils because of gravity override. Microbial EOR entails the use of microorganisms and their metabolites to mobilize capillary trapped oil. This method of EOR is cost-effective as it utilizes cheap raw materials from corn syrups, molasses, and agricultural by-products. Unfortunately, the raw materials for microbial EOR require huge facilities for their cultivation and have limited application due to high sensitivity and logistic problems especially on offshore platform [7].

Chemical EOR methods are adjudged to have a high efficiency, thus, they have witnessed numerous field applications [8]. The method basically involves tuning the efficiency of the injected waterflood to alter the rock-fluid and/or fluid-fluid properties of the reservoir. Hence, a high pore displacement and/or sweep efficiency is achieved, and consequently a higher recovery factor. The chemicals injected for EOR include alkaline, surfactant, polymer and more recently nanoparticles [9, 10]. Sometimes, a binary combination of the chemicals may be used to explore the

#### *An Overview of Natural Surfactant Application for Enhanced Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.104935*

synergic mechanism of the chemicals for a higher oil recovery. Several binary combinations used comprises of alkaline-surfactant flood, alkaline-polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer flooding [11–14]. The mechanism of alkaline and surfactant lowers the interfacial tension (IFT) between the oleic and aqueous phase and alter the wettability of the porous media, thereby, improving the pore scale displacement efficiency. On the other hand, the polymers thicken the viscosity of the injectant and, thus, reduce the mobility ratio and enhance the sweep efficiency [9, 10, 12, 15].

Surfactant flooding involves the use of surfactant molecules also referred to as surface active agents which are amphiphilic molecules with a hydrophilic (polar) head and hydrophobic (non-polar) tail [16, 17]. The hydrophobic tail, which is mostly oil soluble, is characterized by a long chain of alkyl groups which may be branched. The hydrophilic head which are mostly water soluble consists of moieties and are classified according to their ionic charge. Surfactant aid microscopic displacement efficiency by reducing IFT of the fluid-fluid interface. By reducing the IFT, the capillary forces of the trapped oil are minimized, and the oil saturation decreases [18]. Consequently, the dimensionless capillary number increases, and the recovery factor increases. Additionally, wettability alteration at the rock-fluid interface, foam generation and emulsification at the oil-interface are other mechanisms through which surfactant aid oil recovery. Surfactants alter wettability of the porous media via coating and/or cleaning mechanism. Besides, the emulsion generated ensure conformance control by creating a stable front while foam generated diverts subsequently injected water to thief zones in the reservoir to aid additional oil recovery [19].

Surfactants are classified based on the hydrophilic head group. The conventional surfactants based on ionic charge are the cationic surfactant, anionic surfactant, zwitterionic (amphoteric) surfactant, and non-ionic surfactant [20]. For cationic and anionic surfactants, the hydrophilic head groups are positively and negatively charged, respectively. Non-ionic surfactants have no charge and, hence, do not ionize in solution but are soluble in water due to the presence of hydrogen bonding between the hydrophilic groups [18]. Zwitterionic surfactant consists of hydrophilic head with positive and negative charges. Recently, the design and use of new surfactant such as Gemini surfactant, viscoelastic surfactant and polymeric surfactant have been exploited for EOR. Gemini surfactant is a surfactant composed of two single-chain surfactants linked by a spacer. The properties of the Gemini surfactants are dictated by the type and length of the spacer [21]. On the other hand, viscoelastic and polymeric surfactants are surfactants that form a supramolecular structure in solution and characterized by a high viscosity with additional ability to decrease interfacial tension which are both beneficial for EOR [22]. Nonetheless, the major issues associated with the use of conventional surfactants are high costs and environmental concerns. With recent issues associated with global warming and persistent regulation to lower environmental impacts on climate change, the industry is dissipating more energy and drive towards surfactant chemicals with less toxicity.

More recently, natural surfactants have received prodigious attention due to their lower toxicity, biodegradable, and environmentally benign, and good efficiency at improving recovery efficiency. Herein, natural surfactant is defined as surfactant synthesized from plants and oil. Natural surfactants possess the property of reducing the surface and interfacial tension in similitude to synthetic surfactants. Additionally, the novel surfactant has shown exemplary characteristics of foaming, emulsification, dispersion and wetting which are desirable for EOR. Herein, a synopsis of the application of natural surfactant and biosurfactant application for EOR was elucidated.

#### **2. Natural surfactant**

Natural surfactants are surfactants synthesized from leaves of plants and oils and they have shown sterling properties for use in EOR. Natural surfactants are either extracted directly or they are synthesized from plants and animal fats. Several methods have been reported for the synthesis of this biodegradable surfactants such as spray drying, freeze drying, Soxhlet extraction process, supercritical CO2 extraction, ultrasonic extraction, microwave extraction, hydrolysis, and esterification process [23]. Moreover, several parts of plants such as leaves, roots, seeds, oils, and flowers have been courted for natural surfactants depending on their constituent components. *Jatropha curcas*, almond seed, *Vernonia amygdalina*, *Ziziphus spina-christi*, palm tree, vitagnus plant, and soapnut plant are several plants that have been exploited for natural surfactants [24–28]. Additionally, oils of plants and animals such as palm oil, coconut oil, rapeseed oil, sesame oil, waste cooking oil, linseed oil, and waste chicken fats have been converted into natural surfactants via esterification process [29–32]. Amino acid is another source of natural surfactant and can be derived from both plants and animals [23]. In similitude to conventional surfactants, the synthesized and/or extracted surfactants can be categorized into non-ionic, anionic, cationic, and zwitterionic surfactants. Other categories of synthesized polymeric, Gemini and viscoelastic surfactants [33, 34].

#### **3. Application of natural surfactant for EOR**

#### **3.1 Interfacial Tension (IFT)**

Interfacial tension is the adhesive tensional force that exists between the molecules of oil and water in porous media that ensures they remain trapped in the pores of the reservoir rock system. To improve recovery factor, the capillary force holding the oil in place must be minimized. This is achieved by lowering the IFT which in turn cause an increase of the capillary number and resultantly cause the residual oil to flow towards the oil bank and later to the production well. When the surfactant is injected into the reservoir rock system, due to their amphiphilic nature, the hydrophilic head of the surfactant aligns with the water and/or brine while the hydrophobic tail attaches with the oleic phase. The IFT of oil-water interface is measured in the laboratory via pendant drop or spinning drop method. Natural surfactant has demonstrated suitability for use in reducing IFT of oil-water interface. An important property of natural surfactant which makes it highly applicable for IFT reduction is its good solubility.

Several studies have demonstrated the viability of natural surfactant for lowering the IFT of crude oil-water interface. Yekeen et al. [26] investigated the IFT and foaming property of natural surfactant extracted from *Sapindus mukorossi*. At high temperature and pressure (80 °C and 8 MPa), the natural surfactant reduced the IFT of the oil-water interface from 23.24 mN/m to 1.59 mN/m. Moreover, the foam stabilized by the saponin-based natural surfactant was stable and perform comparatively well to conventional sodium dodecyl sulfate SDS-stabilized foam. Bahraminejad et al. [35] examined the IFT and foaming characteristic of surfactant extracted from *Gundelia tournefortii* plant. The surfactant lowered the IFT from 28 mN/m to 3 mN/m and generated stable foams. Imuetinyan et al. [36] evaluated the performance of natural surfactant extracted from *Vernonia Amygdalina* at oil-water interface. The natural surfactant lowered the IFT at oil-brine interface from 18 mN/m to 0.97 mN/m in the presence of NaCl brine. Additionally, the emulsion stabilized by the natural

#### *An Overview of Natural Surfactant Application for Enhanced Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.104935*

surfactant remained stable for longer periods. This implies that the use of the natural surfactant as injectant will ensure good conformance control in the reservoir.

Additionally, natural surfactant has demonstrated good stability and sterling properties at high salinity and high temperature conditions. Zhang et al. [37] synthesized a natural zwitterionic surfactant from castor oil and evaluated the salt tolerance and thermal stability and foaming performance. At 33,000 mg/l salinity and 50 °*C* , the synthesized surfactant maintained strong interfacial activity, which demonstrates good use for EOR. Zhang et al. [32] studied the performance evaluation of novel bio-based surfactant from waste cooking oil. The synthesized bio-based zwitterionic surfactant reduced oil-water IFT to 0.0016 mN/m at low dosage of 0.1 g/l. Kumar et al. [38] noted that bio-based polymeric surfactant synthesized from Jatropha oil was stable in 2.5 wt.% brine concentration and reduced the IFT of the oil-water interface from 22.4 mN/m to 0.33 mN/m. Hence, the application of bio-based natural surfactant shows good potential for EOR due to their stability and sterling interfacial properties at harsh condition typical of reservoir condition.

#### **3.2 Wettability**

Wettability is a pore scale displacement property and usually defined as the tendency of a fluid to spread on or adhere to a surface in the presence of other immiscible fluid. In similitude to conventional surfactant, natural surfactant has shown good property for altering the wettability of porous media from oil-wetting condition to water-wetting condition. Water-wetting condition is desired for better recovery efficiency (see **Figure 2**). Using contact angle measurement, Deng et al. [39] defined water-wetting condition as contact angle of 0 ° –70 ° , intermediate wetting condition as 70 ° –110 ° , and oil-wetting condition as contact angle 110 ° –180 ° . By modifying the wettability of the rock substrate to water-wetting condition, the capillary adhesive force that strongly attaches the oil to the rock diminishes, thus, allowing oil to flow. The interaction of the surfactant and the rock may cause alteration of the wettability condition depending on the type of surfactant injected and the porous media.

Numerous studies have indicated the ability of natural surfactant to cause wettability alteration of porous media. Imuetinyan et al. [25] observed that the natural surfactant extracted from *Vernonia Amygdalina* altered the wettability of sandstone surface from 118.5 ° to 45.7 ° . Similarly, Singh et al. [40] evaluated the wettability of surfactant extracted from Fenugreek seeds. The surfactant reduced the IFT of oil-water interface to 44 ° . Zhang et al. [37] reported wettability alteration from 92.04–38.79 ° using natural surfactant synthesized from castor oil. Moreover, natural surfactant synthesized from soybean oil reduced the wettability of rock substrate by 52.08% to 44.1 ° [41].

**Figure 2.** *Wettability alteration of reservoir rock system [9].*

Chen et al. [34] synthesized a thermally stable and salt tolerant natural surfactant from waste cooking oil and evaluated it wettability alteration potential. The biobased surfactant altered the wettability of simulated formation water containing 0.5 g/l of the surfactant from 96.17 ° –30.7 ° . The contact angle decreased further to a meager 27.8 ° on further increment of the surfactant concentration to 3.0 g/l.

Furthermore, Kumar et al. [24] synthesized natural surfactant from Jatropha oil and evaluated the wettability on oil-wet quartz surface. The synthesized surfactant altered the wettability of the quartz surface to water-wetting condition. Despite the ability of natural surfactant to alter wettability to water-wetting condition, many of the natural surfactant do not alter the wettability to strongly water-wetting condition (contact angle <30° ). Hence, future research should focus on modifying the structure of the natural surfactant to improve it interaction and efficiency with reservoir rock system. Moreover, wettability studies of natural surfactant on porous media focused more on their behavior on quartz surface and sandstone. More studies of natural surfactant behavior on carbonate (calcite, dolomite, and limestone) surface are required.

#### **3.3 Adsorption**

Adsorption is an important property that demonstrates the economic viability of the chemical flooding process [42]. Low retention of chemicals is desired to ensure an economic and cost-effective recovery process. Due to their amphiphilic nature, the injection of surfactant into porous media is followed by the interaction of the surfactant with the rock via electrostatic, van der Waals, ion exchange and association, polarization of the π electrons, and hydrophobic interaction depending on the type of surfactant. The adsorption of natural surfactants has been studied on sandstone and carbonate reservoir rocks and showed minimal adsorption desired for chemical EOR process [43]. Yusuf et al. [44] studied the adsorption behavior of natural surfactant from soapnut fruit on carbonate rocks by batch adsorption experiments using surface tension techniques. They reported lower retention of the natural surfactant compared to ionic surfactants (cationic CTAB and anionic SDS). This was attributed to the weaker hydrogen bonding of the non-ionic surfactant.

Additionally, Kesarwani et al. [45] examined the adsorption property of novel biodegradable surfactant synthesized from Karanj oil on sandstone. The anionic surfactant had 15% lower retention compared to conventional anionic surfactant (SDS). Abbas et al. [46] performed a comparative study of saponin-based natural surfactants from Fenugreek, Sugar beet leaves and chickenpeas on quartz sand surface using UV-Vis spectrophotometer. They reported lower adsorption of the natural surfactant in high salinity conditions and adduced this phenomenon to the compact configuration of the surfactant and the compression of the electrical double layer. Ahmadi et al. [47] investigated the utilization of natural surfactant extracted from *Ziziphus spina-christi* (ZSC). Adsorption studies of the surfactant on carbonate rock samples via batch tests. The surfactant showed no sign of precipitation, but the presence of salt cations increases the adsorption of the surfactant due to electrostatic attraction force between the positive charge of the carbonate rock surface and the negative charge of the hydroxyl group on the surfactant.

#### **3.4 Oil displacement**

The major aim of deploying surfactant as a chemical injectant is to boost oil recovery. Oil displacement test is used in the laboratory to estimate recovery factor of injectant. Several studies have been carried out to ascertain the oil recovery potential

*An Overview of Natural Surfactant Application for Enhanced Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.104935*

**Figure 3.** *Cumulative oil recovery of surfactant flooding [36].*

of natural surfactant when used as injectants in sandstone and carbonate rocks. Saxena et al. [48] evaluated the oil recovery potential of surfactant synthesized from palm oil. The injection of 0.5 pore volume (PV) of surfactant in sandpack caused an improved recovery factor of 25–27% over conventional waterflooding. Nowrouzi et al. [49] evaluated natural surfactant synthesized from *Myrtus communis*. The surfactant yielded 14.3% incremental oil recovery when injected in carbonate core plugs. Alsabagh et al. [30] investigated oil displacement properties of green surfactant synthesized from waste cooking oils. 0.4 wt.% of the surfactant generated from palm kernel oil yielded 24.3% incremental oil recovery, respectively. Imuetinyan et al. [36] recorded 15% incremental oil recovery from core flooding procedure of saponinbased natural surfactant performed at high-pressure high-temperature condition. The SBNS performed better than conventional Triton X-100 under the same condition as depicted in **Figure 3**. Ahmadi et al. [50] explored the use of surfactant derived from *Glycyrrhiza glabra* for EOR. 8 wt.% of the newly extracted surfactant yielded 36% incremental oil recovery. Nafisifar et al. [29] applied surfactant synthesized from linseeds in sandstone cores. The natural surfactant injected after water flooding process yielded a 7.9% incremental oil recovery. Notwithstanding the numerous research of the application of natural surfactant for oil recovery, some aspects still need to be clarified in subsequent research. Notably, the concentration required for some natural surfactants are extremely high which may make the EOR process uneconomical.

#### **4. Conclusion**

This paper reviews the previous studies on natural surfactant application for EOR. The natural surfactants are benign and biodegradable and offer an alternative for existing conventional surfactants. Experimental studies show that natural surfactant can lower the IFT at the oil water interface. Moreover, the application of natural surfactant alters wettability of oil-wet cores to water-wetting condition. Adsorption studies of natural surfactant show that natural surfactant exhibit moderate retention behavior in reservoir cores and compares well to existing conventional surfactants. Moreover, oil displacement studies confirm that the application of natural surfactant can improve the recovery factor. Future studies on natural surfactant should focus on modeling their flow and transport behavior in porous media and scaling up natural surfactant application for field studies.

### **Conflict of interest**

The authors declare no conflict of interest.

### **Author details**

Afeez Gbadamosi1 \*, Adeyinka Yusuff<sup>2</sup> , Augustine Agi<sup>2</sup> and Jeffrey Oseh3,4

1 College of Petroleum and Geosciences, King Fahd University of Petroleum and Minerals, Dhahran, Saudi Arabia

2 Department of Chemical and Petroleum Engineering, Afe Babalola University, Ado-Ekiti, Nigeria

3 Department of Petroleum Engineering, Universiti Teknologi Malaysia, Johor, Malaysia

4 Department of Petroleum Engineering, Federal University of Technology Owerri, Nigeria

\*Address all correspondence to: aogbadamosi2@live.utm.my

© 2022 The Author(s). Licensee IntechOpen. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

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#### **Chapter 6**

## Improving the Heavy Oil Recovery by Surfactants from Wastes

*Ahmed Mohamed Al Sabagh and Asmaa Mohamed*

#### **Abstract**

The amount of crude oil available must be sufficient to meet global demand. As a result, the oil industry has been obliged to recover oil from more difficult places and develop methods for enhanced oil recovery (EOR). This chapter focuses on the phase behavior properties inside the reservoir in connection with surfactant flooding and oil/brine systems in relation to enhanced oil recovery. To achieve this purpose, three groups of nonionic and anionic surfactants were prepared from waste and local materials. The surface activity and thermodynamic properties for three surfactant groups have been investigated at reservoir conditions. The solubilization parameters and relative phase volume were also studied to determine the optimal solubilization parameters and optimal salinity. The dynamic IFT and contact angle were measured at the optimal salinity. The sand pack flooding by using surfactant system predicted the performance of microemulsion in oil recovery by surfactant individually and its blends on chemical flooding system in semipilot EOR unit.

**Keywords:** green surfactants, waste materials, surface tension, interfacial tension, thermodynamic, adsorption mechanism, reservoir conditions, phase behavior, solubilization parameters, chemical flooding

#### **1. Introduction**

The amount of crude oil available must be sufficient to meet global demand. As a result, the oil industry has been obliged to recover oil from more difficult places and develop methods for enhanced oil recovery (EOR). This chapter focuses on the phase behavior properties inside the reservoir in connection with surfactant flooding and oil/brine systems in relation to enhanced oil recovery. To achieve this purpose three groups of nonionic and anionic surfactants were prepared from waste and local materials. The surface activity and thermodynamic properties for three surfactant groups have been investigated at reservoir conditions. The solubilization parameters and relative phase volume were also studied to determine the optimal solubilization parameters and optimal salinity. The dynamic IFT and contact angle were measured at the optimal salinity. The sand pack flooding by using surfactant system predicted the performance of microemulsion in oil recovery by surfactant individually and its blend and this applied on chemical flooding system in semi pilot EOR unit.

#### **2. Enhanced oil recovery**

There are several types of oil recovery mechanisms, including primary, secondary, and tertiary recovery. Primary recovery produces less than 20% of the original oil present in place (OOIP). In secondary recovery, the oil produced by water or gas flooding to make pressure maintenance. The final stage of oil production is tertiary recovery, also known as enhanced oil recovery (EOR). Then the oil recovery falls into the following three categories:


**Improved oil recovery** (IOR): Improved oil recovery (IOR) is a broad term that refers to a variety of activities. Improved oil recovery (IOR), which is synonymous with EOR, refers to any process or practice that improves oil recovery. IOR includes EOR processes, also include other practices, such as waterflooding, pressure maintenance, infill drilling, and horizontal wells.

**Enhanced oil recovery**(EOR): Injection of fluids that are not present in reservoirs such as surfactants. EOR is the process of injecting external materials into reservoirs to manage interfacial tension (IFT), fluid characteristics, wettability, and overcome pressure retention forces in order to recover trapped crude oil from pores and transport it to a production well. The capacity to control the flow of displacement fluids, also known as mobility control, is one feature of EOR operation that has significant effects on all processes. In order to commercialize the EOR process, its economic viability is more vital than any other factor [1, 2].

#### **2.1 EOR processes**

Water flooding is the most widely used technique and has been used for a long time. The water flooding does not remove all of the oil from the production zone. The tertiary recovery then becomes the main goal for producing residual oil. The oil that remains after primary and secondary recovery is distributed throughout the reservoir's pores. Oil trapping is primarily caused by capillary and viscous forces.

The common classifications of different EOR processes are:


#### **2.2 Chemical EOR or chemical flooding**

Chemical processes involve the injection of a specific chemical liquid that effectively creates desirable phase behavior properties in order to improve oil displacement. These displacing fluids have low interfacial tension (IFT) with the displaced crude oil. The main chemicals used in EOR chemical flooding are alkaline, surfactants, and polymers. Each material has a certain mechanism for enhancing the oil flow properties. Alkali behaves as in situ surfactants, where the alkali function groups react with the naphthenic carboxylic groups of crude oil forming in situ sodium salt surfactants. The surfactants are prepared on the surface and then injected inside reservoirs. They improve the oil production by reducing the IFT between crude oil and connate water forming an emulsion that has low viscosity and the ability to make wettability alteration. In case of polymers, they added to the displacing water to increase its viscosity in order to control and make sweeping for the residual oil present in porous media, therefore, the oil production efficiency increases. Generally, there are several types of polymers that are used in this field. The most commercially attractive polymers are polyacrylamides (PAM) and polysaccharides (Biopolymers). In chemical EOR flooding process, hydrolyzed polyacrylamides (HPAM) give higher viscoelasticity, and they are preferred over polysaccharides [3, 4].

#### **2.3 Surfactant flooding**

One of the most promising methods for increasing oil productivity from lowpressure reservoirs is surfactant-assisted enhanced oil recovery. Surfactant flooding is an approved EOR technique for getting residual oil out of a reservoir. The goal of surfactant injection into the reservoir to improve the oil recovery factor is to change the fluid/fluid interaction by lowering the IFT between oil and brine, as well as the fluid/rock properties by changing the wettability of the porous medium, or a combination of both mechanisms. The hydrophilic head dissolves with water when surfactant solutions are poured into oil reservoirs with brine, whereas the hydrophobic tail reacts with crude oil components. The adsorbed film is produced as a result of the interaction between the oil and the alkyl tail of the surfactant, thus lowering the IFT at the oil/water interface. The mechanism by which a surfactant alters the wettability of conventional rock pores is known as a cleaning mechanism, in which the surfactant adsorbs at the oil-wet layer and then changes the surface wettability from oil-wet to water-wet. In addition to having a high surface activity and wettability, good surfactants should be biodegradable and nontoxic. The surface activity and thermodynamic properties provide information on the arrangement of surfactant molecules between two phases and the reduction of surface tension. The micellization in bulk and adsorption at interface can be studied by Gibb's isotherm. Micellization and adsorption are important in understanding the factors that affect CMCs values, such as structural effect. When surfactant concentrations reach critical micelle concentrations (CMCs), micelles develop. Reservoir parameters like pressure, temperature, and salinity of formation water influence CMC and interfacial phenomena (IFT). IFT is one of the most measured parameters to be lowered to less than 10<sup>2</sup> mN / m [5–7].

#### *2.3.1 Surfactant flooding mechanism*

Surfactant flooding improves pore-scale displacement efficiency through the mechanism of interfacial tension reduction, wettability alteration, or a combination of both mechanisms.

#### *2.3.1.1 Interfacial tension reduction*

Due to oil entrapment by capillary forces, it is nearly impossible for water to displace all of the oil in the pore scale during secondary recovery by water flooding. This capillary force is measured by a dimensionless capillary number (Nc) defined in Eq. (1) as:

$$\mathbf{Nc} = \mu\nu/\sigma\cos\Theta\tag{1}$$

where **μ** is the displacing fluid viscosity, **v** is the displacing Darcy velocity, **Ɵ** is the contact angle, and **σ** is the I**FT** between the displacing fluid (water) and the displaced fluid (oil). **Nc** is closely related to residual oil saturation and oil recovery and increases as residual oil saturation decreases. Consequently, a higher **Nc** will result in a higher oil recovery A typical brine flooding has a **Nc** in the range of 10�<sup>7</sup> to 10�<sup>6</sup> . From Eq. (1), this can be achieved in three ways: (1) increasing the displacing fluid viscosity (**μ**); (2) increasing the injection fluid velocity (**v**); (3) reducing the IFT (**σ**).

#### *2.3.1.2 Wettability alteration*

Wettability is the tendency of a solid surface to attract a specific type of fluid in the presence of other immiscible fluids. The position, distribution, and movement of fluids inside a reservoir rock system are determined by the wettability of the rock surface. Most oil reservoirs are classified as oil-wet, water-wet, or mixed wet. Surface imaging tests, zeta potential measurements, spontaneous imbibition, and contact angle measurements can all be used to assess this feature of the reservoir rock system. The contact angle, which is defined as the point where the interface of the oil and water meets at the rock surface, is used in the majority of studies of wettability alteration measurements. A surface with a contact angle greater than 90° is considered oil-wet, while a surface with a contact angle less than 90° is considered water-wet. Changing the wettability of a surface from oil-wet to water-wet reduces capillary adhesive force and increases reservoir oil permeability [8, 9].

#### *2.3.2 Surfactant types and their structure*

EOR has investigated a number of surfactants for use in oil recovery. They are classified into anionic surfactants, nonionic surfactants, cationic surfactants, and zwitterionic surfactants depending on the nature of the hydrophilic head group.

#### *2.3.2.1 Anionic surfactant*

Anionic surfactants are the most commonly used surfactants. The majority of surfactant flooding EOR work has been done on sandstone reservoirs. The surfaceactive portion of this class of surfactant bears a negative charge such as carboxylate (COO), sulfate (SO4 ), or sulfonate (SO3 ), though in association with a cation usually an alkaline metal (Na<sup>+</sup> or K<sup>+</sup> ).

#### *2.3.2.2 Cationic surfactant*

Cationic surfactants are surfactants that have a positive charge on their hydrophilic head, but only in conjunction with a halide group. In water, they split into an amphiphilic cation and an anion. This surfactant class is easily attracted to the negatively charged surfaces of rocks and is very effective at changing reservoir rock wettability [10].

#### *2.3.2.3 Nonionic surfactant*

Nonionic surfactants, unlike cationic and anionic surfactants, do not ionize in aqueous solution. Alcohol, phenol, ether, ester, and amide are examples of nondissociable hydrophilic functional groups. Meanwhile, the lipophilic group consists of the alkyl or alkyl benzene group. Despite the lack of ionic charge, the hydrophilic group is soluble in water due to its inherent polarity induced by the presence of hydrogen bonds and van der Waals interactions. Nonionic surfactants have a higher salinity tolerance than ionic surfactants; however, they have a lesser IFT reduction.

#### *2.3.2.4 Zwitterionic surfactant*

Zwitterionic surfactants are characterized by the presence of anionic and cationic surface charges on their hydrophilic head. When they dissociate, they display anionic and cationic characteristics. They can also withstand high salinity and high temperatures. Betaine and sulfobetaine are two examples of this type of surfactant.

### **3. Microemulsions**

#### **3.1 Type and structure of microemulsion**

The structure of the microemulsion plays an important role in the physicochemical properties of the applied fields. Direct (oil dispersed in water, o/w), reversed (water dispersed in oil, w/o), and bi-continuous microemulsions are the three basic types. Multiple microemulsion, like multiple emulsion, is sometimes possible. The structure of a microemulsion is determined by salinity, water content, co-surfactant concentration, and surfactant concentration [11].

#### **3.2 Applications in enhanced oil recovery (EOR)**

In oil and gas industry, the approach to emulsion and/or microemulsion preparation has been associated with the application of energy to a mixture of oil, water, and emulsifier. Because of the rheological and thermodynamical properties of emulsions, injection of emulsions and/or microemulsions into oil reservoirs has been recognized as a potential tool for oil recovery [12].

#### **3.3 Microemulsions for enhanced oil recovery**

Microemulsions could also be used to improve oil recovery because of the ultra-low interfacial tension values achieved between the contacting oil and water microphases. Microemulsion flooding can be applied over a wide range of reservoir conditions. Microemulsion techniques involve pumping water into the oil reservoir that contains a small amount of surfactant and other chemicals. The natural acids in the trapped oil react with this solution to form a microemulsion. The surfactant molecules break down the interfacial tension to mobilize oil and enable it to escape from the rock. Microemulsions are prepared from a mixture of oil, water, or brine and a surfactant. In some cases, the addition of a co-surfactant (alcohol) is required to ensure the stability of the microemulsion. An oil-in-water (O/W) microemulsion in equilibrium with the oil excess phase (Winsor I), a water-in-oil (W/O) microemulsion in equilibrium with the water excess phase (Winsor II), and a microemulsion in equilibrium with both the water and oil excess phases (Winsor III) are prepared for a given overall composition. Surfactant flooding operations are best performed with middle-phase microemulsions. Hence, it is fundamental to maintain the middle microemulsion phase as long as possible during the process of surfactant flooding. Many factors influence the best surfactant composition for a microemulsion system, including pH, salinity, temperature, and so on. Due to the ability to dissolve oil and water concurrently, as well as the system's ability to achieve very low interfacial tension, tertiary oil recovery using microemulsions has been the main focus. Microemulsion flooding is a miscible displacement procedure that optimizes oil recovery by reducing capillary forces on oil droplets in the reservoir [13–15].

#### **3.4 Surfactant flooding: Optimum phase type and optimum salinity**

As salinity rises, surfactants are able to solubilize an increasing amount of oil and a diminishing amount of water. The salinity at which the microemulsion solubilizes equal amounts of oil and water is called the optimal salinity. Salinity scan tests are commonly used to assess the phase behavior of surfactant formulations before conducting time-consuming core-flood testing. When the minimum interfacial tension is linked to the solubilization parameters at the optimal salinity, the presence of viscous, structured phases, and stable macroemulsions can be easily monitored. The equilibrium phase behavior appears to shift from a lower-phase microemulsion to an upper-phase microemulsion over a narrow salinity range. Depending on salinity, a microemulsion can exist in three types of systems: type I, type III, or type II. The system is type I below a certain salinity. The system is classified as type II above a certain salinity. If the salinity is in between, the system is type III. The interfacial tension (IFT) of microemulsion/brine is lower in a type III system than in a type I system, and the IFT of microemulsion/oil is lower in a type II system. At optimum salinity, the two IFTs are equal. If the optimum salinity decreases with surfactant concentration, it will also decrease as the surfactant solution progresses. As a result, as the surfactant solution progresses, the decreasing salinity will be consistent with the decreasing optimum salinity, ensuring that the optimum salinity is maintained. Therefore, The oil recovery factor in a type III system is higher than in a type I or type II system. Core flooding must be used to establish the optimal phase type. The phase type with the highest oil recovery factor is the optimum salinity type [16, 17].

In this chapter two types of surfactants have been synthesized the first one is nonionic surfactants derived from polyethylene glycol having different molecular weights of 400,600,1000 and 2000 with either mixed fatty acids of jatropha oil and waste cooking oil or dodecylbenzene sulfonic acid and the other is anionic surfactants, which are derived from either mixed fatty acid of the oil used or dodecylbenzene sulfonic acid. The chemical structure confirmation of the prepared surfactants was recorded using a Thermo Fisher Scientific Spectrometer (400–4000 cm<sup>1</sup> Nicolet Is10) (FT-IR spectra). The phase behavior and solubilization parameters of the prepared surfactants were studied. The phase behavior of surfactant-brine-oil system in the oil recovery by microemulsion system was evaluated. Finally, sets of flooding experiments for the prepared surfactants and their blends with and without cosurfactants (Iso Propanol) on sand-packed model at critical micelle concentration (CMC), different temperature and different salinities was performed.

#### **4. Materials**


As the results of EOR operations, this work interested to prepare three groups of surfactants to be used in this application. The abbreviation of these groups was; group1 (EABS9, 14, 23, 46 and EABSNa), group2(EHJ9, 14, 23, 46 and EHJNa), group3 (EHWO9, 14, 23, 46 and EHWONa). All of these research work results, data analyses and comparative studies are elaborated on and discussed in this chapter [18].

#### **5. Surface active properties of surfactants prepared at 25°C**

The surface tension of the three surfactant groups was measured in the formation water at a temperature of 25 ° C. The first group of surfactants was based on dodecyl benzene sulfonic acid (**G1**), the second group on jatropha oil (**G2**), and the third group on waste cooking oil (**G3**). The breakpoint of the plots was used to determine the values of (CMC) and surface tension at CMC (γCMC). G1 has lower CMC values

than the other two groups, which could be related to the presence of a sulfonic group in the molecules, which deactivates the surfactant molecules'solubility in the solution. The values of CMC in relation to the number of ethylene oxides in the tested groups were found to decrease with an increase in the number of ethylene oxide units until a certain number was reached, after which they increased. This behavior may be caused by two factors. The first factor is the ethylene oxide chain coiling, which influences the solution's solubility. The second factor could be due to surfactant molecule solubility in formation water as a result of salts in the water breaking down hydrogen bonds. These results of CMC show that the G2 and G3 can efficiently saturate any interface, demonstrating surface properties like flexibility and low interfacial tension that can be used in EOR. The surface tension was reduced by the surfactant molecules, allowing for a quantitative investigation that revealed continual adsorption at the interface. So that, at concentrations lower than the CMC, the possibility of micelle production is not fully realized. The effectiveness (πCMC) is the difference between the surface tension values of the formation water only and with surfactant at CMC and determined by Eq. (2):

$$
\pi\_{\rm CMC} = \gamma\_{\rm w} - \gamma\_{\rm s} \tag{2}
$$

where γ<sup>w</sup> is the surface tension of formation water and γ <sup>s</sup> is the surface tension of surfactant solution at CMC*.* By calculating the average of πCMC, it was found that the πCMC of G1 was higher than the other two groups. The maximum surface excess concentration (Γmax) is the maximum amount up to which surfactant adsorption can be obtained at the surface, and this depends on the molecular structures of the interacting component. The adsorption degree was calculated by Gibb's isotherm and given by Eq. (3):

$$
\Gamma\_{\text{max}} = - (\mathbf{1}/\text{RT}) \left( \delta \mathbf{\dot{\gamma}} / \delta \text{lnC} \right) \tag{3}
$$

where **Γmax** is the surface excess concentration (mol/cm<sup>2</sup> ), T is the absolute temperature, **R** is a universal gas constant (8.314 Jmol�<sup>1</sup> K�<sup>1</sup> ), and (**δץ/δlnc**) is the slope of γ-lnC. The minimum area occupied by surfactant molecules (**Amin**) determines the average area occupied by each adsorbed surfactant molecule at the air-liquid interface at saturated surface. The **Amin** was determined by Eq. (4):

$$\mathbf{A}\_{\rm min} = \mathbf{1} \times \mathbf{10}^{16} / (\mathbf{NA} \,\Gamma\_{\rm max}) \tag{4}$$

where **NA** is the Avogadro's number (6.022 � <sup>10</sup>23). The results of Amin are decreased by increasing the ethylene oxide units for the three groups, but the Amin values of G1 are lower than those of G2 and G3. This could be because the surfactant molecules in the G1 have three chemical spaces; the benzene ring, the SO2, and the ethylene oxide chain, this may result in vertical adsorption of molecules and the formation of a monolayer on the surface or interface, lowering the coiling affinity of the ethylene oxide chain and lowering the Amin by increasing the units of ethylene oxide. The coiling affinity of the ethylene oxide chain in these groups may be obtained by two factors. The first factor is the formation of water which inhibits the formation of hydrogen bonds, lowering the solubility of surfactant molecules, and causing coiling. The second explanation could be related to the unsaturation of the double bond in the oleic chain, which results in cis and trans configurations, increasing the ethylene oxide chain's coiling affinity. The low values of Amin show that the ability for the formation of oil/surfactant/solution microemulsion resulting in lowering the interfacial tension, further the oil displacing capacity should be improved. The adsorption efficiency (Pc20) is given by the negative logarithm of the surfactant concentration that reduces the surface tension of the pure solvent by 20mN/m. The adsorption efficiency is determined by Eq. (5):

$$\mathbf{Pc\_{20}} = -\log \mathbf{C\_{20}}\tag{5}$$

where C20 is the amount of surfactant required for reduction of pure solvent surface tension by 20 mN/m and this means that C20 is the minimum concentration that denotes the adsorption saturation at the surface. Therefore, C20 measures the efficiency of surfactant molecules' adsorption at the air-liquid interface. The higher the Pc20 number, the more surfactant molecules adsorb. The surfactants of G1 achieved the lowest concentration in terms of adsorption efficiency. The surface pressure was in the maximum value with G3. This means that surfactants can successfully saturate any interface by displaying surface properties with the appropriate flexibility while also lowering the IFT**.**

#### **6. Surface active properties of EABS14, EHJ23, and EHWO14 at different temperatures**

Three surfactants were chosen, one from each group, to demonstrate how temperature affects their surface and thermodynamic properties. The selectivity of these surfactants is determined by how much surface tension and area per molecule are reduced (Amin). When the temperature was raised, the CMC of these surfactants increased slightly, while the surface tension decreased. This could be due to warmth breaking the hydrogen bond, making the surfactant molecules more soluble in the solvent, resulting in higher concentration consumption and adsorption. Temperature increased adsorption efficiency, indicating that the surfactants' high surface activity was responsible. The effectiveness decreased with an increase in temperature. When the temperature was raised, the Amin exhibited a small increase. The decrease in Γmax


#### **Table 1.**

*Surface activity for EABS14, EHJ23, and EHWO14 in formation water at different temperatures [18].*

values and increase in Amin could be owing to thermal agitation caused by repulsive forces between bulk phase molecules. The repulsive forces in the bulk phase are based on the breakdown of hydrogen bonds (**Table 1**).

#### **7. Thermodynamic properties of the prepared surfactants**

Surface tension measurements were used to calculate the micellization and adsorption free energy at the interfaces. The adsorption of surfactant molecules at the air-liquid interface under equilibrium conditions reduces surface tension. The number of surfactant molecules adsorbed at the interface per unit area was provided by Gibbs adsorption equation. The CMC values play a vital role in calculating ΔGmic. This is shown in the following Eq. (6):

$$
\Delta \mathbf{G}\_{\rm mic} = \mathbf{R} \mathbf{T} \; \ln \mathbf{c}\_{\rm CMC} \tag{6}
$$

where ΔGmic is the molar Gibbs energy of micellization in KJ/mol. The change in the adsorption free energy was calculated from Eq. (7):

$$
\Delta \mathbf{G\_{ads}} = \Delta \mathbf{G\_{mic}} - [\mathbf{0}.6022 \times \Pi\_{\text{cmc}} \times \mathbf{A\_{min}}] \tag{7}
$$

The production of micelles in the bulk phase of the solution was indicated by negative ΔGmic values. Negative ΔGmic values indicate that micellization is a spontaneous association dissociation process that allows surfactant molecules adsorbed at the interface. At the same time, the negative values of ΔGmic increase the free energy of the solvent, which compensates for the surfactant molecules prefer to adsorb on the surface and interface before and during micelle formation. The negative values of ΔGads indicated that the adsorption of the surfactant molecules at the air-liquid interface is a spontaneous process. Due to an increase in the curvature of the air/aqueous surface, the greater negative values of ΔGads increase. This means that as temperature rises, the number of potential vacancy sites for adsorption increases, and more surfactant molecules should be adsorbed at the interface. Surfactant molecules establish a microemulsion at the CMC for all surfactants tested, and as a result of negative ΔGmic and ΔGads values, the surfactant molecules may form a stable microemulsion phase and demonstrate effective interfacial contact with the surrounding media. Based on the micelle aggregation and adsorption capabilities of these three surfactant groups, it is expected that they will contribute to the right formulations to generate microemulsions for use in oil solubilization and displacement processes in the enhanced oil recovery field (**Tables 2** and **3**).


**Table 2.**

*Thermodynamic parameters of micellization for EABS14, EHJ23, and EHWO14 in formation water at different temperatures [18].*

*Improving the Heavy Oil Recovery by Surfactants from Wastes DOI: http://dx.doi.org/10.5772/intechopen.106707*


**Table** 

**3.** *Thermodynamic parameters of adsorption and structural effects of EABS14, EHJ23, and EHWO14 in formation water at different temperatures [18].*

**Figure 1.** *IFT for Blank, EABS14, EHJ23, and EHWO14 at Different Temperatures [18].*

#### **8. Interfacial tension in the reservoir condition**

When assessing surfactant effectiveness for oil recovery, the interfacial tension is a more important factor to consider. The lower the IFT value, the better the ability to generate microemulsion, which is more effective in displacing oil stuck in reservoir pore throats. The interfacial tension (IFT) was measured for the EABS14, EHJ23, and EHWO14 between the used formation water and crude oil by using Attension Theta High-Pressure Chamber (Sessile Method) (ASTM ISO 19403-5) to evaluate their affinity in the enhanced oil recovery application (EOR). The IFT was measured at different temperatures (25, 35, 45, and 50°C) in high saline formation water TDS (200 103 ppm) at the CMC. The data showed that by increasing temperature the IFT decreased. The data also ranged from 10<sup>1</sup> to 10<sup>4</sup> mN /m and these results were considered suitable for the application of these surfactants in the EOR. By increasing the temperature, the IFT decreased marginally [19]. This is because the temperature increases the free energy of the surfactant system, which helps to push the surfactant molecule to adsorb on the interface, resulting in oil solubilization in the form of microemulsion and, as a result, higher oil recovery (**Figure 1**).

#### **9. Solubilization parameters and phase behavior**

The volume of solubilized oil divided by the volume of solubilized surfactant in the microemulsion is the oil solubilization ratio. Similarly, the water solubilization ratio in a microemulsion is defined as the volume of water solubilized divided by the amount of solubilized surfactant. The difference in volume between the initial aqueous phase

#### *Improving the Heavy Oil Recovery by Surfactants from Wastes DOI: http://dx.doi.org/10.5772/intechopen.106707*

and excess water is used to calculate the volume of solubilized water. The optimum solubilization occurs when the solubilization of oil and water are equal. The solubilization curves are generated using data relevant to each tube. Water solubilization method with salinity variation can be used to determine the phase behavior and phase boundary of a microemulsion system. From the experimental results, it was found that when the salinity increases the solubilization values increase up to a certain value and then decreases. The salinity at which the solubilization is highest is termed optimal salinity. In the present study, the optimal salinity was found at 100 <sup>10</sup><sup>3</sup> ppm. At the optimal salinity, the middle phase of microemulsion has the ability to solubilize equal amounts of oil and brine. After the optimal salinity, the water solubilization decreases by increasing salt concentration. As the salinity increases, the microemulsion phase changes from Winsor type Ι to Winsor type II to Winsor type III. These phenomena can be illustrated on the basis of the interaction of the inter droplets and interfacial bending stress. As salt concentration increases, salt ions attract some water molecules, reducing the number of water molecules available to interact with the charged component of the surfactant and raising the demand for solvent molecules. As a result, the contact between the surfactant's hydrophilic head groups becomes stronger than in solution. Then the interfacial film turns from positive value to zero to negative value and this corresponds to phase transition from oil water (O/ W) Winsor type Ι to bicontinuous phase Winsor type III to water oil (W/O) Winsor type II so increasing salinity causes phase transition from lower to middle to upper phase of microemulsion [20, 21].

#### **10. Effect of salinity on the IFT**

In case of oil/water system, the IFT was found to be high. The use of salt causes a significant shift in the IFT. The IFT between oil and microemulsion dropped as salt concentration was raised, however, the IFT between water and microemulsion increased. After certain concentration, the IFT microemulsion and oil increased. The minimum IFT

**Figure 2.** *Interfacial Tension Vs. Salinity for EHWO14+EABS14+Cs [18].*

is obtained at certain salinity called optimal salinity. The reduction of IFT in presence of salt is interpreted as the following. Surfactant materials are responsible for lowering the IFT (interfacial tension) between oil and water. The presence of salt in the aqueous phase increases the concentration of surface-active species that are present in crude oil at the crude oil/water interface then lowering the IFT. Above the optimal salinity, the salts prevent the molecules of surfactant from dissolving in aqueous phase because of the increasing repulsive forces of electrostatic double layer [22]. As a result, the amount of surfactant in the oil phase was lowered, and the IFT could not be reduced (**Figure 2**).

#### **11. Phase diagram of micro emulsion system**

The pseudo ternary diagram of surfactant, co-surfactant/brine/crude oil system has been constructed for different types of surfactant in this study. The brine is considered as a single pseudo component, (S+Cs) is another single component, and crude oil is the last component. The importance of the construction of ternary diagram is to determine the composition of microemulsion. It is also important to prepare the microemulsion with low concentration of surfactant from economical point of view. The ternary diagrams for surfactant/ formation water/crude oil were constructed for surfactants and their blends. It was found that the microemulsion region in case of blend is larger than the area in surfactant only (**Figure 3**). This may be due to the presence of isopropanol co-surfactant, which increase the solubility of the surfactant molecules in the oil phase and increase the stability of microemulsion. In general, the microemulsion region of surfactant and its blends derived from waste cooking oil is larger than the microemulsion region of surfactant and its blends derived from jatropha oil. This may be due to by measuring the surface and IFT of surfactant solution it was found that the

IFT values of surfactant derived from waste cooking oil are lower than the IFT values of surfactant derived from jatropha oil. This also may be due to the higher adsorption of surfactant molecules at the interface and this is shown from the thermodynamic properties where the ΔGads of surfactant derived from waste cooking oil group is more negative than ΔGads the surfactant derived from jatropha oil.

#### **12. Enhanced oil recovery factor of the surfactant flooding**

The successful surfactant flooding as a chemically EOR process is to design the surfactant slug at an optimum surfactant concentration. The flooding process depends on many factors, such as temperature, the critical micelle concentration (CMC), adsorption properties on the sand-packed model, interfacial tension, contact angle, and alteration wettability at the surface or the interface between core and the formation water. Different sets of flooding experiments for the EHJ23, EHWO14, and their blends with and without co-surfactants (isopropanol) were drawn with the injected pore volume of sand-packed model at CMC concentration, different temperatures (50, 70°C), and different salinities (50 <sup>10</sup><sup>3</sup> , 100 <sup>10</sup><sup>3</sup> , 200 <sup>10</sup><sup>3</sup> ppm). After the flooding of the surfactant solution, the trapped oil in the pores is mobilized due to the decrease in the IFT between the oil and the injecting surfactant solution. So that it can interact with the trapped oil and reduce the IFT and solubilize the oil by forming oilin-water emulsion and changing the rock wettability, further the recovery factor (RF) increases. This indicates that the behavior of surfactant molecules causes complete adsorption and a stable electric double layer at the interface and that the IFT is minimized so that the maximal solubilization of oil by surfactant is obtained at the CMC, optimal salinity, and optimum temperature. The RF dropped after CMC, indicating that an increase in surfactant molecules led to the formation of a multilayer of surfactant adsorption, which could lead to the formation of an inverse emulsion, resulting in a reduction in the RF (**Figure 4**).

**Figure 4.** *Cumulative Oil Recovery Vs. Injected Pore Volume for EHWO14 at 70°C.*

#### **13. Conclusion**

In this chapter, attention has been paid to prepare some anionic and nonionic surfactants from waste and nonedible materials to evaluate their performance in enhanced oil recovery (EOR). The surface activity, thermodynamic properties, and interfacial tension for surfactants have been investigated under reservoir conditions. The phase behavior of surfactant-brine-oil system is an important key in evaluating the oil recovery by microemulsion system so the phase behavior and solubilization parameters of the prepared surfactants were studied. The solubilization parameters for oil in microemulsion Vo/Vs are increasing as a function of salinity, whereas the solubilization parameters of water Vw/Vs are decreasing and this is shown for surfactants (EHWO14+EABS14+Cs). The optimal salinity was found to be 100 <sup>10</sup><sup>3</sup> ppm and the minimum IFT is obtained at optimal salinity. The pseudo ternary diagram of surfactant, co-surfactant/brine/crude oil system has been constructed for surfactants (EHWO14+EABS14+Cs). Sets of flooding experiments for the EHWO14 and their blends were performed on sand-packed model at CMC concentration, different temperatures, and different salinities and maximum RF was achieved under these conditions.

### **Author details**

Ahmed Mohamed Al Sabagh1,2 and Asmaa Mohamed1,2\*

1 Application Department, Egyptian Petroleum Research Institute, Cairo, Egypt

2 Enhanced Oil Recovery Unit (EOR) at EPRI, Egypt

\*Address all correspondence to: ammnaser94@gmail.com

© 2022 The Author(s). Licensee IntechOpen. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

*Improving the Heavy Oil Recovery by Surfactants from Wastes DOI: http://dx.doi.org/10.5772/intechopen.106707*

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[2] Baojun B. EOR performance and modeling. Journal of Petroleum Technology (JPT). 2016;**68**:60-73

[3] Olajire AA. Review of ASP EOR (alkaline surfactant polymer enhanced oil recovery) technology in the petroleum industry: Prospects and challenges. Energy. 2014;**77**:963-982

[4] Thomas S. Enhanced oil recovery—an overview. Oil Gas Science and Technological Review. 2007; **63**:9-19

[5] Samanta A, Bera A, Ojha K, Mandal A. Comparative studies on enhanced oil recovery by alkali– surfactant and polymer flooding. Journal of Petroleum Explorer and Production Technology. 2012;**2**:67-74

[6] Bera A, Kumar T, Ojha K, Mandal A. Adsorption of surfactants on sand surface in enhanced oil recovery: Isotherms, kinetics and thermodynamic studies. Application Surface Science. 2013;**284**:87-99

[7] Panthi K, Weerasooriya U, Kishore K. Mohanty enhanced recovery of a viscous oil with a novel surfactant. Fuel. 2020; **282**:118-882

[8] Liu Q, Dong M, Ma S, Tu Y. Surfactant enhanced alkaline flooding for Western Canadian heavy oil recovery. A Physicochemical Engineering Aspects. 2007;**293**:63-71

[9] Chen W, David S. Schechter Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid

reservoirs. Journal of Petroleum Science and Engineering. 2021;**196**: 107702

[10] Pal S, Mushtaq M, Banat F, Al Sumaiti AM. Review of surfactantassisted chemical enhanced oil recovery for carbonate reservoirs: Challenges and future perspectives. Petroleum Science. 2018;**15**:77-102

[11] Uma AB, Saaid IBM, AdebayoSulaimon A, Pilus RBM. A review of petroleum emulsions and recent progress on water in-crude oil emulsions stabilized by natural surfactants and solids. Journal of Petroleum Science and Engineering. 2018;**165**:673-690

[12] López-Montilla JC, Herrera-Morales PE, Pandey S, Shah DO. Spontaneous emulsification: Mechanisms, physicochemical aspects, modeling, and applications. Journal of Dispersion Science and Technology. 2002;**23**(1-3): 219-268

[13] Sharma T, Kumar GS, Sangwai JS. Enhanced oil recovery using oil-inwater (o/w) emulsion stabilized by nanoparticle, surfactant and polymer in the presence of NaCl. Geosystem Engineering. 2014;**17**(3):195-205

[14] Bera A, Mandal A. Microemulsions: A novel approach to enhanced oilrecovery: A review. Journal of Petroleum Exploration and Production Technology. 2015;**5**(3):255-268

[15] Li X, He G, Zheng W, Xiao G. Study on conductivity property and microstructure of Triton X-100/ alkanol/n-heptane/water microemulsion. Colloids and Surfaces A: Physicochemical and Engineering Aspects. 2010;**360**(1-3):150-158

[16] Santanna VC, Curbelo FDS, Castro Dantas TN, Dantas Neto AA, Albuquerque HS, Garnica AIC. Microemulsion flooding for enhanced oil recovery. Journal of Petroleum Science and Engineering. 2009;**66**(3, 4):117-120

[17] Zhao J et al. The structure effect on the surface and interfacial properties of zwitterionic sulfo betaine surfactants for enhanced oil recovery. The Royal Society of Chemistry. 2015;**5**:13993-14001

[18] Al Sabagh AM et al. Surface activity and thermodynamic properties of some green surfactants from wastes in formation water at reservoir conditions. Journal of Dispersion Science and Technology. 2020;**43**:385-398

[19] Al-Sabagh AM. Surface activity and thermodynamic properties of watersoluble poly ester surfactants based on 1, 3 dicarboxymethoxy-benzene used for enhanced oil recovery. Polymers for Advanced Technologies. 2000;**11**:48-56

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[22] Roshanfekr M, Johns RT. Prediction of optimum salinity and solubilization ratio for microemulsion phase behavior with live crude at reservoir pressure. Fluid Phase Equilibria. 2011;**304**:52-60

#### **Chapter 7**

## Chemical Enhanced Oil Recovery: Where Do We Stand? Recent Advances and Applications

*Anastasia Ivanova and Alexey Cheremisin*

#### **Abstract**

In this chapter, the recent advances in chemical flooding, including the application of nanoparticles, novel surfactants, and the combination thereof will be discussed and described. The main rock and reservoir fluids properties that influence the effectiveness of chemical flooding will be addressed. The emphasis will be given on wetting properties and recent advances in methods for measuring wettability. The technological and economic challenges associated with chemical injection will be posed, and reсent solutions will be given. Especially, the challenge of applying chemical EOR methods to carbonate reservoirs will be covered, and suggestions to overcome it will be given. Moreover, the current worldwide applications of chemical EOR will be discussed and future plans will be outlined.

**Keywords:** chemical EOR, surfactants, polymers, nanoparticles, carbonate reservoirs, micro- and macro-wettability

#### **1. Introduction**

Alternative renewable energy sources, such as solar, wind, or hydrogen energy, are actively developing in the world. However, traditional oil and gas are still dominating sources of energy, and their global demand is growing continuously. Therefore, it is important to continue developing and enhancing recovery from existing oil fields or discovering new production fields [1]. However, the reserves of conventional, easily accessible hydrocarbons are consistently declining, which is attributed to the fact that the production of conventional oil has surpassed the increase of its reserves. Therefore, since the last several decades, there has been an increasing trend toward the development of unconventional sources of oil and gas, such as viscous (heavy) oils and bitumen, oil sands, oil and gas saturated low-permeability reservoirs, which will significantly contribute to reserves restocking. The majority of unconventional resources are deposited in remote regions with complex geological conditions (depth, porous media structure, mineralogical variations, etc.) under harsh reservoir properties, such as high temperature and salinity, and thus, their development involves the application of new technologies of exploration and recovery [2].

Several stages of recovery and reservoir development are known [3]. At the first stage, also called the primary stage, oil is extracted using the natural energy of the formation, due to which oil flows freely to the production well. However, over time, the initial reservoir pressure decreases, which consistently leads to a decrease in the oil recovery factor. In this case, secondary methods (or improved oil recovery methods) are used to maintain the pressure, such as the injection of water or gas into the reservoir. It is well known that after waterflooding more than 50% of residual oil will remain unproduced [4]. Such inefficient recovery after secondary methods is attributed to the reservoir's rocks and fluids properties, such as hydrophobic wetting properties and high oil viscosity. Therefore, enhanced recovery methods (or tertiary methods) are applied to change or modify reservoir properties of matured fields, facilitating the displacement of oil toward the production well. These methods include thermal formation stimulation (steam and air injection), chemical flooding (surfactant and polymer injection), gas injection (N2 and CO2), microbes injection, and combination of the methods. Generally, tertiary EOR technologies aid in incremental oil recovery more than primary and secondary methods [5]. However, the effective deployment of EOR methods requires a deep understanding of the mechanisms behind the fluid distribution and displacement through the porous media, which in turn control overall oil production.

In the face of diverse EOR advances, chemical methods are one of the promising techniques applied to recover residual and trapped oil [6, 7]. However, due to some challenges associated with chemical mismatch and high cost, porous trapping, and plugging issues, in the past decades, not many projects have been conducted in the fields. Nevertheless, the rising oil prices and market demand encourage many researchers around the world to further develop chemical EOR technology to make it more efficient yet cost-effective and environmentally friendly.

This review focuses on the fundamentals of chemical EOR in order to explain the main aspects behind screening procedures for chemicals and suitable reservoirs with an emphasis on surfactant injection. The work discusses the main types of studied surfactants and their properties (phase behavior, interfacial tension [IFT], and wettability) that should be evaluated prior to their application and the methods that are usually used. Subsequent sections describe the main advantages and challenges associated when surfactant flooding applied in sandstone or carbonate reservoirs. The novel approaches of using nanoparticles in surfactant flooding, so-called nanoEOR, will be addressed. Finally, examples of field applications will be given. This work mainly focuses on the overall properties of common chemicals and practical recommendations rather than on detailed descriptions of phenomena related to chemical EOR.

#### **2. Fundamentals of chemical EOR**

Various methods are being developed and applied to improve and enhance oil recovery from different reservoirs [2]. Conventionally, the effectiveness of the method or technology applied for reservoir development is assessed by means of the oil recovery factor (%) which is usually calculated by multiplying several factors:

( ) ( ) ( ) ( ) ( ) = − × × × − Recovery % pore scale displacement % sweep % drainage % commercial cut off % , (1) *Chemical Enhanced Oil Recovery: Where Do We Stand? Recent Advances and Applications DOI: http://dx.doi.org/10.5772/intechopen.106732*

where pore-scale displacement is a measure of how much of the oil has been pushed out from any of the rock accessed by injected fluids, sweep calculates how much reservoir rock has been reached by injected fluids, drainage is an extent to which wells can access all the separate segments of the reservoir, and commercial cut-off indicates the limit of economic production.

Generally, pore-scale displacement and sweep efficiency are two main factors that can be controlled and modified by applying EOR methods. As a result, it facilities the oil displacement toward the production wells, increasing the overall recovery factor.

Waterflooding is the widely used method for decreasing residual oil saturation by pore-scale oil displacement. However, reservoirs show low oil recovery during waterflooding because more than half of the original oil in place (OOIP) is still left trapped in the complex pore matrix due to the low capillary number of water [8]. The capillary number is defined as the ratio between viscous and capillary forces (Eq. (2)) and controls the residual oil saturation [9] and as a result, the pore-scale displacement.

$$N\_{\epsilon} = \frac{\upsilon \ast \mu}{\gamma \ast \cos \theta},\tag{2}$$

where *μ* is the brine viscosity, *v* is Darcy's velocity, *θ* is contact angle, and *γ* is IFT between oil and water phases.

It is well known [10] that to reduce residual oil saturation (i.e., enhance oil recovery), the capillary number should be increased drastically to 10−3 or higher from the typical number of waterflooding—10−7. Indeed, in works [11, 12], it was shown that an increase in the capillary number to 10−4 to 10−3 reduces the residual oil saturation to 90%, and if the capillary number reaches about 10−2, then the residual oil saturation tends to reach zero. Note that the relation between the capillary number and residual saturation is known as the capillary desaturation curve.

In practice, to modify the capillary number, chemical EOR methods, including surfactant flooding, are widely used. As it can be seen in Eq. (2), a capillary number can be increased in several ways: (1) by increasing the viscosity of the injected fluid; (2) by increasing injection fluid velocity; (3) by decreasing IFT between immiscible phases (water and oil); and (4) by decreasing a contact angle. However, an increase in the velocity of the injected fluid can lead to an undesirable increase in the injection pressure compared with the reservoir pressure. Therefore, more often, EOR methods are applied to change and modify the injected fluid viscosity, IFT, or wettability. For instance, the viscosity of injected water can be increased by adding long-chain molecules such as polymers, which due to the formation of a network of topological entanglements, impart high viscosity to the aqueous solution and in some cases, viscoelastic properties [13]. It is important to note that the main purpose of polymer addition is increasing sweep efficiency. Indeed, when a low-viscosity fluid (water) is injected into a reservoir, it will tend to bypass oil sections of the reservoir as it moves along, creating an uneven (fingered) profile. These fingers can have different shapes ranging from a "fleshy" finger [14] to a "skeletal" finger [15]. As a result, it will displace residual oil unevenly, leaving many pores with hydrocarbons untreated. Therefore, in order to reduce the mobility of the water and viscous fingering, polymers are added to the displacement fluid (water).

Furthermore, to reduce the IFT at the interface between two immiscible liquids, such as displacement fluid and oil, as well as to modify the wetting angle, surfactant solutions are used due to their unique properties [16]. Indeed, surfactant molecules are amphiphilic—they consist of hydrophobic (oil-soluble) and hydrophilic (watersoluble) parts. Due to amphiphilic properties, surfactant molecules can self-orient at the surface or interface via hydrophobic or electrostatic interactions, resulting in a reduction of surface energy. Depending on the charge of the hydrophilic group, surfactants are divided into ionic (charged) and nonionic (not charged). The most commonly used surfactants in chemical EOR are listed in **Table 1.** Conventionally, the type of surfactant for a specific reservoir is chosen accordingly to the screening procedure performed with reservoir rocks and fluids. A summary of general properties applicable to every type of surfactant is illustrated in **Table 1**.

Some types of surfactants have been found to be very effective in terms of IFT reduction, as such carboxylate surfactants can lower the IFT from 20 to 50 mN/m to 10−3 to 10−2 mN/m at reservoir conditions and thus increase the capillary number in 1000 times [17, 18]. The decrease in IFT between the displacement and displaced fluids makes the oil more mobile in the pore throats due to reduced capillary trapping.


#### **Table 1.**

*The list of typical surfactants used in chemical EOR and their general properties.*

*Chemical Enhanced Oil Recovery: Where Do We Stand? Recent Advances and Applications DOI: http://dx.doi.org/10.5772/intechopen.106732*

However, one of the main properties of surfactants that are lowering the IFT to values ~10−3 to 10−2 mN/m is significantly influenced by various factors, such as surfactant type and concentration, the concentration of monovalent and divalent ions in brine (salinity), water-oil ratio (WOR), oil composition, reservoir mineral composition, temperature, and pressure. Therefore, some surfactants that lower IFT at ambient conditions may not be applicable under reservoir conditions (high temperatures and mineralization).

Although many factors affect surfactants' ability of IFT reduction, their common property is the existence of optimal concentration, at which the minimum of IFT can be observed. This concentration is known as critical micelle concentration (CMC) and varies for different surfactants depending on their chemical structure. The CMC is the main controlling parameter for surfactant properties and needs to be optimized for every surfactant system for enhanced oil recovery [19]. Typically, this concentration lies in a range between 0.001% and 0.01% for commonly used surfactants. By increasing the surfactant concentration above the CMC point, the IFT curve starts to grow slightly [17, 19]. Notably, although, at the CMC point, the minimum IFT is reached, for practical cases concentration of surfactant is chosen of one–two orders of magnitude higher because of high retention and adsorption of surfactant molecules during penetration through the pore networks.

#### **3. Wettability of formation rocks, its modification, and measuring methods**

Capillary number can be also increased by reducing the contact angle cosθ (Eq. (2)) that is determined by the forces between injected fluid and rock surfaces. This contact angle is defined in terms of rock-wetting properties. According to the general definition, wettability is the property of a liquid to maintain contact with a solid surface that stems from intermolecular interactions [20].

In terms of oil recovery, wettability is the main parameter that governs produced and injected fluids distributions in the porous networks, which in turn affects the properties of the multiphase flow of reservoir fluids. The wetting state of rock surfaces stems from a chemical equilibrium between rock/oil/brine that formed over years. Generally, wetting preferences of surfaces are divided into three types such as water-wet (hydrophilic), mixed-wet, and oil-wet (hydrophobic). In the water-wet state, oil forms droplet with the minimum contact area at the surface, showing a contact angle θ~0°. If oil drop spreads, the surface is considered hydrophobic or oilwet with a contact angle close to 180°. When rock surfaces do not exhibit particular wetting preferences, the wetting state is referred to intermediate. In this case, the contact angle can be calculated by the balance of the surface tension forces between phases (Young equation) that determine the shape of a drop on the surface. Notably that when rock surfaces demonstrate several wetting preferences, for example, some areas are hydrophilic and others are hydrophobic, the wettability type is mixed.

The wetting state of reservoir rock controls the arrangement and migration of oil, brine, and gas throughout the pore channels. The distribution of wetting and nonwetting fluids depends on capillary forces, and thus, wetting fluid tends to occupy small pores while nonwetting remains in large pores. In terms of oil recovery, this means that if the rock exhibit hydrophobic wetting state, water as a non-wetting fluid will penetrate through the pores with a larger size, leaving small pores unaffected [18]. This phenomenon explains the low efficiency (low recovery factor) of waterflooding

in hydrophobic oil reservoirs (i.e., carbonates), as the water moves through the big pores, while major oil resides in small pores, where water cannot access due to the capillary pressure effect.

This phenomenon is the main reason that prevents developing especially carbonate reservoirs by waterflooding, because the majority of them exhibit hydrophobic or oil-wet wetting preferences [21, 22]. Compared with sandstones, the wettability of carbonate reservoirs appears to be more complex. Indeed, the initially hydrophilic wetting state of carbonate rocks can be changed towards more hydrophobic when interactions between minerals and oil components take place. In research work, several possible mechanisms of wettability alteration due to such interactions have been proposed:


It is important to estimate the initial wettability of rocks accurately for selecting a proper EOR technology for reservoir development. Conventionally, wettability studies are conducted at a core-scale by using Amott–Harvey [27], USBM [28, 29], and contact angle methods [30]. The popularity of these laboratory methods stems from their cost-effectiveness and simplicity. Although Amott–Harvey and USBM methods are widely used in laboratories, they provide information about the average wettability of the core sample. Furthermore, the investigation of reservoir rock wettability by these methods is limited, because as it was shown in work [31], only samples with permeability no less than 10 mD can be studied. Moreover, these methods cannot account for a mixed wettability state (case when different surfaces of rock exhibit both hydrophilic and hydrophobic wetting preferences), as it impossible to determine the number of areas, which have water-wet or oil-wet states, and thus they provide only the integral wettability index.

Another commonly used method for wettability investigation is measuring the contact angle between fluids (water or oil) and the surface. This method is based on the analysis of droplet shape when it spreads on the surface. In this case, wettability is assumed in terms of contact angle values. As such, wettability is referred to hydrophilic if oil forms an angle 0° < θ < 70° with the surface, intermediate wet—70° < θ < 110°, and hydrophobic—110° < θ < 180°. The reverse trend of contact angle values is considered if using water instead of oil. The main difference between contact angle measurements and USBM and Amott–Harvey methods is that by measuring angles the data of wetting preference of a particular sample surface can be collected, and thus mixed wettability state can be determined correctly. However, the contact angle measurements cannot provide the average or integral wettability index. Therefore, in order to measure the wettability accurately, one should consider using a combination of different methods.

Nevertheless, direct study of the fluid-rock interactions by these methods is constrained, as they measure the average wettability on macroscale (mm) and cannot account for rock surface properties, such as its roughness, chemical composition, and pore structure that significantly influence fluids flow and distribution [32]. Therefore, in the past decades, advanced microscopic techniques, including highresolution scanning electron microscopy (SEM), transmission electron microscopy (TEM) coupled with cryogenic technique and environmental scanning electron

#### *Chemical Enhanced Oil Recovery: Where Do We Stand? Recent Advances and Applications DOI: http://dx.doi.org/10.5772/intechopen.106732*

microscopy (ESEM) are proposed as new methods for the investigation of reservoir fluids arrangement in porous structure [33, 34]. For example, the authors [33] illustrated that by collecting the elemental maps of rock samples via coupled SEM imaging with the X-ray analysis of the elements the arrangement of reservoir fluids (brine and oil) in the porous network can be obtained. Furthermore, with the recent advances in microscopy, it has become possible to use cryogenic techniques (i.e., Cryo-TEM) and ESEM in order to study surface wettability at microscale (μm) [35, 36]. Indeed, in the work [37] authors carried out the wettability measurements of the middle Bakken samples using ESEM technique. The authors concluded that the results obtained at microscale could be applied for more accurate calculation of multiphase flow parameters (e.g., relative permeability and capillary pressure), which in turn would improve the development of primary or secondary oil recovery processes. Moreover, the application of microscopic techniques is particularly essential while developing the carbonate reservoirs, as these reservoirs show complex wetting behavior due to challenging pore structure, mineral composition, and heavy oil. Indeed studying the rock/brine/oil chemical interactions would give an insight into how to optimally modify wettability to mixed or water-wet, which in turn would increase oil recovery from carbonate reservoirs.

The authors [22] investigated the reason for the hydrophobic wetting properties of carbonate reservoir rocks using combined microscopic tools. The advanced microscopic technologies were first used to identify the adsorbed organic layers on rock surfaces that were proposed to be the key reason for hydrophobic wetting state of carbonates. It was shown [22] by using the ESEM approach that the surface had two wetting preferences. As such, the surface areas that were covered with hydrocarbon layers had hydrophobic wetting properties, while pure calcite areas exhibited hydrophilic state. This result was also confirmed by EDXS analysis of different areas. It was also revealed that the main parameters of multiphase fluids distribution in the pore channels, such as capillary pressure curves, could be evaluated more accurately when using data of microscale wettability variations and the thickness of the organic layers (180 ± 12nm).

Furthermore, the obtained results can be used to explanation of the reasons for complex wettability behavior in carbonate reservoir rocks. Indeed, based on developed methods [22], it was suggested that some asphaltenes or oil acids could react with calcium ions on the surface by the ionic bond between calcium (Ca2+) and oxygen (O− ) from the carboxyl group (COO− ). This is the initial layer of hydrophobic organic layers on carbonate surfaces, on which other oil hydrocarbons can adsorb, forming bigger hydrophobic regions. As a result, initial hydrophilic wettability alters toward more oil-wet and water-injection becomes ineffective. Importantly, this explanation can be also applied when developing other carbonate oil reservoirs with high content of carboxylic acids or asphaltenes in oil.

Furthermore, in [38], it was shown that the wettability of carbonates measured by a common laboratory method (contact angle) that differs from wettability measured in corresponding areas of the surface at the microlevel. As such, results demonstrated that wettability at the microlevel was mixed (i.e., hydrophilic and hydrophobic zones) while at the macrolevel surface showed only hydrophobic wetting preferences. These findings bring into question the applicability of macroscale data in reservoir modeling for enhanced oil recovery and geological storage of greenhouse gases.

Traditionally, wettability should be altered towards more hydrophilic in order to increase the oil recovery factor from hydrophobic reservoirs (including carbonates). As a result, spontaneous water imbibition into a porous media will be promoted,

leading to the enhancement of oil recovery. In this regard, many different surface active chemicals, such as surfactants, have been widely tested for wettability alteration towards more water-wet. **Table 2** summarizes some literature data on change in water advancing contact angle after treating rock surfaces with various surfactants.

As can be observed from **Table 2**, the values of the contact angle between surface and water correspond to the hydrophilic wetting state after treatment of different surfactants.

Notably, the effectiveness of wettability alteration depends on molecular structure and the ionic nature of surfactants. For instance, it was shown that some anionic surfactants with ethoxy and proxy groups in a mixture with Na2CO3 were promising agents for alteration of wettability of carbonate surfaces from oil-wet to water-wet [42]. Contrary to this, the authors [39] suggested that cationic surfactants could be more effective for wettability changing in carbonates reservoirs than anionic ones. The authors explained this by the formation of ion pairs that occur between negatively charged oil components adsorbed on carbonate surfaces and positively charged surfactants. As a result, desorption of oil components from surfaces will be facilitated, leading to a consistent oil recovery increase. Furthermore, it was illustrated that wettability is altered more effectively due to the electrostatic interactions than by hydrophobic interactions. This hypothesis has been also supported by work [43], where the authors studied the wettability alteration process of carbonate cores using


#### **Table 2.**

*Summary of contact angles changes after surfactants treatment.*

#### *Chemical Enhanced Oil Recovery: Where Do We Stand? Recent Advances and Applications DOI: http://dx.doi.org/10.5772/intechopen.106732*

different surfactants—anionic (SDS), cationic (CTAB), and nonionic (TritonX-100). The authors showed that cationic surfactant (CTAB) was more effective than anionic (SDS) and non-ionic (TritonX-100) ones in terms of changing the wetting state of the carbonate surface. The phenomenon of wettability changing has been explained by taking into account the irreversible desorption of acids adsorbed onto carbonate surfaces by CTAB surfactants via electrostatic interactions. Notably, for nonionic surfactants, the mechanism of wettability alteration was explained by ion exchange and polarization of π-electrons, whereas for anionic surfactants, the main mechanism of wettability alteration was found to be via hydrophobic interactions between surfactant tail and adsorbed hydrophobic oil components [43].

However, although the evident effectiveness of surfactant flooding mechanisms in wettability alteration, an optimal surfactant that can be both technically and economically feasible has not been found yet. Indeed, the main challenge is surfactant adsorption or retention during the injection process in the reservoir. The unproductive loss of surfactant decreases its effectiveness to lower brine/oil IFT and changing wettability.

Furthermore, although anionic surfactants have been found to be very promising for IFT reduction at reservoir conditions, the value of their adsorption onto hydrophobic or mixed-wet carbonate surfaces was estimated to be higher than in sandstone reservoirs. For instance, it was shown [44] that the adsorption value of typical anionic surfactant onto sandstone and limestone samples equaled 0.03 mg/g rock and 0.21 mg/g rock, respectively. In contrast, the adsorption value of cationic surfactant onto carbonate rocks was calculated to be only 0.12 mg/g rock [44]. The high adsorption value of anionic surfactants in carbonate reservoirs can be explained by the existence of electrostatic interactions between positively charged rock surfaces and negatively charged surfactant heads. Moreover, in high salinity brines of 5% CaCl2, MgCl2, or NaCl, the adsorption of anionic surfactant has been observed to be even higher due to the increased positive zeta-potential of the carbonate surfaces [45].

Therefore, although surfactants have been regarded as promising surface-active agents and laboratory experiments demonstrated their potential in wettability alteration, their industrial applications are limited due to high retention and adsorption onto reservoir rocks. Subsequently, different additives, such as alkalis and nanoparticles, have been studied as sacrificial agents to surfactant molecules in order to decrease their loss and improve efficiency for field applications.

#### **4. Recent advances in chemical EOR: application of nanoparticles as oil/brine IFT and wettability modifiers**

Traditionally, surfactant flooding as chemical EOR method has been developed and applied in sandstone oil reservoirs due to its economic and technical effectiveness [7]. Contrary to this, developing carbonate oil reservoirs with surfactant flooding is limited because of high loss of surfactant, resulting in increased operational costs. Nevertheless, many modeling and experimental studies have shown that surfactant flooding in oil-wet carbonate reservoirs could be a promising way of enhancing oil recovery [17]. Several effective ways have been proposed in the literature in order to overcome the high surfactant loss in carbonate reservoirs.

Conventionally, so-called "sacrificial" agents, such as sodium carbonate, sodium bicarbonate, or polyacrylate have been used to decrease the adsorption of surfactants [46]. The popularity of alkali addition to surfactants stems from their ability to

increase pH (>7–8) that lead to an alteration of surface charge from positive toward more negative, which in turn results in a decrease in electrostatic attraction of anionic surfactant molecules to negatively charged surfaces.

However, it should be pointed out that some carbonate reservoirs consist of anhydrites (*CaS*O4 ) that can react with alkali and cause the precipitation of *CaC*O3 following the reaction [47]:

$$\text{CaSO}\_4 + \text{Na}\_2\text{CO}\_3 \rightarrow \text{Na}\_2\text{SO}\_4 + \text{CaCO}\_3 \downarrow \tag{3}$$

Interestingly, it was observed that nonionic or cationic surfactants show less adsorption value on carbonate rocks in comparison with anionic ones [39]. Although, the adsorption value of these surfactants is low, they have been reported to show less effectiveness in terms of oil/brine IFT reduction due to their chemical structure and properties [45]. Therefore, there is still a need for studies of developing the optimal chemical mixtures consistin of surfactants and "sacrificial" agents that can significantly reduce IFT, and exhibit low adsorption values.

Recently, the application of nanoparticle dispersions has been proposed to be promising alternative agent instead of alkali for decreasing adsorption of surfactant onto carbonate surfaces [48]. In the last years, the interest of using nanoparticles for enhancing effectiveness of surfactant EOR has been rapidly growing, with many studies being carried out [48–51]. Nanofluids or nano-assisted chemical EOR is defined as an injection of fluids that consist of 1–100 nm nanoparticles in colloidal suspension.

Several groups of nanoparticles exist—magnetic (Fe3O4, etc.), metal and nonmetal oxides (ZrO2, TiO2, SiO2, Al2O3, ZnO, etc.), and metallic (Cu, Pt, Au, Ag, etc.) [52–54]. For EOR purposes, the most commonly studied groups of nanoparticles are metal and non-metal oxides due to their unique physical and chemical properties [55]. For instance, these nanoparticles have shown good tolerance to mono and divalent ions (brine) and high thermal stability [56]. In this regard, many experimental studies have been carried out with these types of nanoparticles in order to evaluate their influence on surfactant EOR.

The main mechanisms of nanoparticles as EOR agents include wettability alteration, water/oil IFT reduction, increasing viscosity of injected fluids, disjoining pressure effect, and preventing asphaltene precipitation. Indeed, as it was shown in work [57], the inclusion of nanoparticles enhanced surfactant properties by increasing the stability of surfactant solutions and by helping in the reduction of oil/brine IFT. Moreover, studies also suggest the nanoparticles reduce the volume of surfactant needed for EOR, and thus improve the project economy.

In recent years, several studies have been reported about the influence of different nanoparticles (SiO2, ZnO2, and Al2O3,) on water/air surface and brine/oil IFTs in mixture with surfactants [50, 58, 59]. However, the influence of nanoparticles on the interfacial layer remains uncertain, with some contradicting trends existed in the literature. For instance, Ravera et al. [60] demonstrated that the surface and IFTs of cationic surfactant upon addition of SiO2 nanoparticles increased. On the contrary, Al-Anssari et al. [61] and Lan et al. [62] reported that the inclusion of a small amount of SiO2 nanoparticles to cationic and anionic surfactants resulted in IFT decrease. Furthermore, these results were supported by a study [63], where IFT reduction was observed in the presence of anionic surfactant and high (10 wt.%) concentration

#### *Chemical Enhanced Oil Recovery: Where Do We Stand? Recent Advances and Applications DOI: http://dx.doi.org/10.5772/intechopen.106732*

of nanoparticles. Moreover, according to the results of Zargartalebi et al. [64], IFT between anionic surfactant solutions with small concentrations (1000 ppm) of hydrophobic or hydrophilic SiO2 nanoparticles and hydrocarbons decreased significantly when the surfactant concentration did not exceed the CMC. However, contrary to this, in the work [59] only a slight IFT reduction between oil and surfactant solutions with 0.5 wt.% ZnO2 nanoparticles was observed. While further increase of surfactant concentration showed no effect on IFT in a range of all nanoparticle concentrations tested [59].

Interestingly the addition of SiO2 nanoparticles to non-ionic surfactant Tween 20 showed a significant reduction of IFT from 44 to 10 mN/m [65]. The IFT decrease from 39 to 17.5 mN/m has been also observed while studying the SiO2/Fe2O3 nanocomposites resulting in an overall 31% OOIP improvement [66]. As can be seen, despite having a significant number of publications in this area, researchers worldwide remain inconclusive over the interfacial behavior of nanoparticles augmented surfactant injection fluids, and further research is required in this area.

Since the development of hydrophobic carbonate oil reservoirs is emerging, different types and combinations of nanoparticles have been tested as additives to surfactant solutions in order to alter wettability towards more water-wet and thus enhance oil recovery [50, 67]. The authors in [67] reported that the addition of SiO2 nanoparticles to anionic surfactant (SDS) aided in the reduction of water contact angle on carbonate surfaces. Importantly, the effect of nanoparticle addition was


#### **Table 3.**

*The summary of nanoparticles and/or nanocomposites effect on the contact angle of water on carbonate surfaces.*

more pronounced when the surfactant's concentration was near CMC. Indeed, it was observed that the water advancing contact angle changed from ∿140° to 72° when only 0.2 wt.% of SiO2 nanoparticles were added to the SDS surfactant solution. Whereas, the treatment in surfactant solution without nanoparticles led to less contact angle reduction ∿150° to 110°, illustrating oil-wet preference of carbonate surfaces.

Therefore, the authors [67] suggested that SiO2 augmented surfactant solutions could be an effective fluid for EOR application in carbonate reservoirs, where the oil recovery process depends on wettability alteration. The effect of different nanoparticles and/or nanocomposites on surfactant property to change the wettability of carbonate surfaces has also been studied in many articles. The results of these studies are summarized in **Table 3**.

As it can be seen in **Table 3**, the inclusion of nanoparticles and/or nanocomposites to surfactant solutions helps in wettability alteration of carbonate rocks toward more hydrophilic. As a result, the oil recovery factor also increases. These results have been obtained in different studies with different types of nanoparticles tested, and thus, nanoparticles have been widely regarded as a promising EOR agent.

Therefore, the application of nano-assisted surfactant flooding may be a new chapter of chemical flooding for developing carbonate reservoirs. However, in order to scale this technology from the laboratory to field applications, more laboratory and modeling studies are required.

#### **5. Field applications and challenges of chemical enhanced oil recovery**

Generally, after many laboratory screening tests (stability, IFT, static and dynamic adsorption, wettability, and core flooding), successful candidates are selected for a single well tracer test (SWTT). In this test, the surfactant is injected into a well as a slug, and the oil saturation before and after is calculated. This test is performed in order to evaluate the amount of oil that can be reduced. Such a test is less expensive and usually is carried out before a field pilot test.

The scheme of injection may be different depending on reservoir conditions. As such, a scheme may include a so-called preflush, followed by a main slug and postflush. The preflush with alkaline is used to dilute the reservoir brine in order to reduce the concentration of divalent ions that can cause unfavorable surfactant degradation. For instance, sodium silicate, sodium carbonate, and sodium hydroxide were used in preflush slug in Bell Creek project and Salem field [78, 79]. As a postfluch slug usually includes polymers (biopolymers or synthetic) for improving the sweep efficiency after surfactant flooding.

Traditional types of surfactants used in EOR include but are not limited to petroleum sulfonate, ethyl sulfate, alkyl benzene sulfonate, carboxylates, etc. Moreover, many new surfactants are being synthesized mainly for EOR applications in high salinity and temperature conditions, such as biosurfactants and Gemini [80]. However, even if a novel surfactant shows promising economic and technical results in the laboratory, there is no guarantee that this surfactant will have the same effect in the field. The main reasons for this are surfactant production in a field-scales (tones), logistics, and the high cost of chemicals used for synthesis. For example, there are many works dedicated to the development of new effective surfactants that would be applicable in high temperatures and salinities conditions [17, 81]. However, when it comes to the field, the economic evaluation limits their implications.

*Chemical Enhanced Oil Recovery: Where Do We Stand? Recent Advances and Applications DOI: http://dx.doi.org/10.5772/intechopen.106732*

**Figure 1.** *Surfactant flooding projects that were conducted worldwide from the 1990s to 2000s [82].*

Therefore, there are not many actual field projects reported in the literature. Moreover, historically, surfactant flooding as an EOR method was developed for sandstone oil reservoirs [17]. This stems from many factors, including pore matrix structure, mild reservoir conditions, low chemicals retention, and adsorption values. Carbonate reservoirs are considered to be promising candidates for surfactant EOR, but exhibit more complex structure and physical-chemical properties than sandstones, and thus only a few projects were conducted with them. **Figure 1** illustrates the number of surfactant projects conducted worldwide from the 1990s to the 2000s. It can be seen that the number for sandstone reservoirs surpasses the number of carbonates [82]. Only two projects were performed in carbonates in the USA—Cottonwood Creek [83, 84] and Yates field [85, 86], and one project in Semoga field Indonesia [87] However, it is interesting to point out that pilot tests of surfactant injection in carbonate reservoirs gave promising results. For instance, the Yates field pilot test showed a two-fold increase in oil recovery factor by using commercial surfactant Shell 91-8 [84, 86]. Therefore, surfactant flooding has been regarded as a promising alternative to CO2 injection in carbonates [88].

It is important to note that in order to increase the applicability of surfactant EOR, the oil price should not be less than 50\$/bbl and the cost of used chemicals should be decreased to a minimum so that the economy of the project will be profitable. This can be done, for instance, by developing the production factories close to the field, which will improve the local chemical production services. Moreover, the governmental support of local development companies is also needed to compensate for the economic risks of chemical EOR.

#### **6. Conclusion**

This chapter presents recent trends in chemical EOR with the emphasis on surfactant flooding and its applications for ensuring cost-effective hydrocarbons production. The mechanism of EOR applications and recent progress in chemical flooding have been addressed. The main challenges of chemical EOR have also been discussed. Field applications of surfactant EOR have been surveyed worldwide, illustrating a trend towards sandstone reservoirs rather than carbonates. Furthermore, a new type of chemical flooding, namely nano-assisted EOR, has been discussed with regards to improving surfactant flooding effectiveness. Nevertheless, the application of this new method is limited to laboratory tests and pilot scales. This can be attributed to some uncertainties associated with technology economics (instability of oil prices),

a lack of understanding of the short-term and long-term environmental impact of nanoparticles applications. Therefore, a few recommendations for the future research of chemical EOR can be highlighted:


### **Acknowledgements**

This work was supported by the Ministry of Science and Higher Education of the Russian Federation under agreement No. 075-10-2022-011 within the framework of the development program for a world-class Research Center.

### **Author details**

Anastasia Ivanova\* and Alexey Cheremisin Skolkovo Institute of Science and Technology, Moscow, Russia

\*Address all correspondence to: anastasia.ivanova@skoltech.ru

© 2022 The Author(s). Licensee IntechOpen. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

*Chemical Enhanced Oil Recovery: Where Do We Stand? Recent Advances and Applications DOI: http://dx.doi.org/10.5772/intechopen.106732*

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Section 4
