Improving the Heavy Oil Recovery by Surfactants from Wastes

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.

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:

• Primary recovery: Recovery by depletion (natural pressure of reservoirs)

• Secondary recovery: Recovery by injecting water or gas flooding

• Tertiary recovery: Recovery of the residual oil by injecting additives not present in reservoir

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:

• Chemical EOR

• Thermal EOR

• Miscible/Immiscible EOR

• Microbial EOR

• Technical Challenges and Futures Techniques in EOR

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 low-pressure 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 10⁻²mN / m [5, 6, 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:

$$\mathrm{Nc}=\mathrm{\mu \nu }/\mathrm{\sigma }\text{cosƟ}$$E1

where μ is the displacing fluid viscosity, v is the displacing Darcy velocity, Ɵ is the contact angle, and σ is the IFT 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 10⁻⁷ to 10⁻⁶. 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 surface-active 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⁺ or K⁺).

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 non-dissociable 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, 14, 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⁻¹ Nicolet Is⁻¹⁰) (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 co-surfactants (Iso Propanol) on sand-packed model at critical micelle concentration (CMC), different temperature and different salinities was performed.

4. Materials

• Purified jatropha oil with a density of 0.908 g/cc and an acid value of 11.87 KOH/gm was used, as well as waste cooking oil with a density of 0.989 g/cc and an acid value of 16.73 KOH/gm was obtained from an Egyptian market. Para toluene sulfonic acid (99%), anhydrous sodium sulfate (99%), and HCl (99%) were obtained from Sigma-Aldrich Company. The solvents, ethanol (99%), n-Hexane (99%), isopropanol (99%), and xylene (99%) were purchased from PIOCHEM Company. The polyethylene glycols (400, 600, 1000, and 2000) were obtained from Alfa Aesar Company. Alkyl benzene sulfonic acid, KOH, and NaCl were purchased from El-Gomhouria Co, Egypt.

• The crude oil used in microemulsion preparation was obtained from General Petroleum Company, Egypt. API gravity at 60 °F 27, asphaltine content 7.63 wt. %, saturates 57wt%, resin content 15 wt. %, aromatic 21wt%, and density is 0.8983 at 15°C.

• The TDS of formation water was 200 × 10³ ppm. Also, formation water was diluted by distilled water to get a salinity of 50 × 10³ and 100 × 10³ ppm. The 50 × 10³ and 100 × 10³ ppm salinity is prepared to represent the formation water’s salinity and study the effect of changing salinity on prepared microemulsions.

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 (γ_CMC). 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 (π_CMC) is the difference between the surface tension values of the formation water only and with surfactant at CMC and determined by Eq. (2):

$${\mathrm{\pi }}_{\mathrm{CMC}}={\mathrm{\gamma }}_{\mathrm{w}}–{\mathrm{\gamma }}_{\mathrm{s}}$$E2

where γ_w is the surface tension of formation water and γ _s is the surface tension of surfactant solution at CMC. By calculating the average of π_CMC, it was found that the π_CMC of G1 was higher than the other two groups. The maximum surface excess concentration (Γ_max) 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):

$${\mathrm{\Gamma }}_{\max }=-\left(1/\mathrm{RT}\right)\left(\mathrm{\delta ץ}/\text{δlnC}\right)$$E3

where Γ_max is the surface excess concentration (mol/cm²), T is the absolute temperature, R is a universal gas constant (8.314 Jmol⁻¹K⁻¹), and (δץ/δlnc) is the slope of γ-lnC. The minimum area occupied by surfactant molecules (A_min) determines the average area occupied by each adsorbed surfactant molecule at the air-liquid interface at saturated surface. The A_min was determined by Eq. (4):

$${\mathrm{A}}_{\min }=1\times {10}^{16}/\left(\mathrm{NA}.{\mathrm{\Gamma }}_{\max }\right)$$E4

where NA is the Avogadro’s number (6.022 × 10²³). The results of A_min are decreased by increasing the ethylene oxide units for the three groups, but the A_min 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 SO_2, 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 A_min 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 A_min 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):

$${\mathrm{Pc}}_{20}=-log{\mathrm{C}}_{20}$$E5

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 (A_min). 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 A_min exhibited a small increase. The decrease in Γ_max values and increase in A_min 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).

Surfactant	EABS14				EHJ23				EHWO14
Temperature	25°C	35°C	45°C	55°C	25°C	35°C	45°C	55°C	25°C	35°C	45°C	55°C
CMC × 10^−3; (mol/L)	1.38	1.58	1.69	1.80	1.98	1.98	2.17	2.38	2.89	3.02	3.12	3.22
Pc20; (mol/L) × 10^−4	0.454	3.35	4.44	5.53	0.167	1.67	3.33	5.00	0.432	4.49	8.39	12.3
γCMC; (mNm^−1)	25.9	22.3	20.35	18.4	26.5	22.5	43.4	18.9	28.5	25.5	22.45	19.4
Γmax; (mol/cm^2 × 10^−10)	2.49	1.73	1.51	1.29	1.84	1.38	1.28	1.18	1.89	1.54	1.50	1.46
Amin; (nm^2 × 100)	0.665	0.96	1.11	1.278	0.900	1.199	1.29	1.400	0.879	1.08	1.11	1.14
πCMC; (mN m^−1)	41.53	33.41	29.69	25.98	40.93	29.21	27.36	25.51	38.93	30.21	27.62	25.02

Table 1.

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

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 ΔG_mic. This is shown in the following Eq. (6):

$${\mathrm{\Delta G}}_{\mathrm{mic}}=\mathrm{RT}{ln}_{\mathrm{CMC}}$$E6

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

$${\mathrm{\Delta G}}_{\mathrm{ads}}={\mathrm{\Delta G}}_{\mathrm{mic}}–\left[0.6022\times {\mathrm{\Pi }}_{\mathrm{cmc}}\times {\mathrm{A}}_{\min }\right]$$E7

The production of micelles in the bulk phase of the solution was indicated by negative ΔG_mic values. Negative ΔG_mic 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 ΔG_mic 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 ΔG_ads 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 ΔG_ads 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 ΔG_mic and ΔG_ads 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).

Surfactant	∆ Gmic; (KJ mol^−1)				∆ Hmic; (KJ mol^−1)				∆ Smic; (KJ^−1 mol^−1k^−1)
	25°C	35°C	45°C	55°C	25°C	35°C	45°C	55°C
EABS14	−16.32	−16.51	−16.74	−16.97	−7.38	−7.27	−7.27	−7.28	0.03
EHJ23	−15.43	−15.94	−16.08	−16.22	−6.49	−6.70	−6.61	−6.53	0.03
EHWO14	−14.48	−14.86	−15.13	−15.41	−2.56	−2.54	−5.03	−2.49	0.04

Table 2.

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

Surfactant	∆ Gad (KJ mol^−1)				∆ Had (KJ mol^−1)				∆ Sad (KJ^−1 mol^−1k^−1)	∆ Gmic -∆ G ads (KJ mol^−1)
	25°C	35°C	45°C	55°C	25°C	35°C	45°C	55°C		25°C	35°C	45°C	55°C
EABS14	−31.50	−35.82	−36.39	−36.96	28.10	25.78	26.71	27.64	0.21	15.81	19.31	19.72	19.99
EHJ23	−37.61	−37.03	−37.38	−37.73	−34.63	−33.95	−34.22	−34.5	0.01	22.18	21.09	21.16	21.51
EHWO23	−35.09	−34.45	−33.52	−32.58	−5.29	−3.65	−1.96	−0.28	0.1	20.61	19.59	18.39	17.17

Table 3.

Thermodynamic parameters of adsorption and structural effects of EABS14, EHJ23, and EHWO14 in formation water 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 10⁻¹ to 10⁻⁴mN /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).

Figure 1.

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

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 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 × 10³ppm. 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 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).

Figure 2.

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

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 ΔG_ads of surfactant derived from waste cooking oil group is more negative than ΔG_ads the surfactant derived from jatropha oil.

Figure 3.

Ternary Phase Diagram of Oil-Brine-Surfactant Blend (EHWO14+EABS14+Cs) System [18].

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 × 10³, 100 × 10³, 200 × 10³ppm). 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 oil-in-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 × 10³ 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.