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Cationic-Nonionic Mixed Surfactants as EOR fluids: Influence of Mixed Micellization and Polymer Association on Interfacial, Rheological and Rock-wetting Characteristics Nilanjan Pal, Mudit Vajpayee, and Ajay Mandal Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b00671 • Publication Date (Web): 30 May 2019 Downloaded from http://pubs.acs.org on June 2, 2019
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Cationic-Nonionic Mixed Surfactants as EOR fluids: Influence of Mixed Micellization and Polymer Association on Interfacial, Rheological and Rock-wetting Characteristics Nilanjan Pal 1, Mudit Vajpayee 2, Ajay Mandal 1* 1Indian 2Oil
Institute of Technology (Indian School of Mines), Dhanbad-826004, India
and Natural Gas Corporation (ONGC), Mumbai-400051, Maharashtra, India *Corresponding Author, Email:
[email protected] Abstract In this article, the efficacy of ionic/non-ionic mixed surfactant systems as a promising chemical route toward enhanced oil recovery (EOR) application is investigated. Critical micelle concentration (CMC) of {CTAB + Tween 60} surfactant system was confirmed using conductivity studies and surface tensiometry. Thermodynamic analyses revealed that both adsorption as well as micellization processes in mixed surfactant compositions are more pronounced/effective as compared to pure surfactant solutions. Addition of polymer resulted in improved micellar stability in mixed surfactant systems by steric interactions. Ultralow IFT values were obtained for mixed surfactant systems by spinning drop technique. In the presence of carboxymethylcellulose (polymer), the viscosity of surfactant slugs are improved, leading to sweep efficiency during oil displacement process. Viscoelasticity investigations reveal that elastic modulus (G’) dominate over viscous modulus (G’’) at angular frequencies >1 rad/s, showing their capability to displace trapped oil through low permeability regions. Mixed surfactant solutions exhibit favourable sessile drop spreading onto oil-saturated rock surfaces and alter wetting characteristics to water-wet state. Surfactant adsorption onto sand reduced significantly in mixed surfactant systems. Flooding studies revealed that nearly 20% of original oil in place (OOIP) was recovered by {mixed surfactant/polymer} chemical fluid injection, after conventional secondary recovery process. In summary, mixed surfactant + polymer fluids constitute an effective driving fluid for extraction of crude oil previously trapped within mature petroleum reservoirs. Keywords Ionic/non-ionic mixed surfactant; Critical micelle concentration; Interfacial tension; Viscosity; Viscoelasticity; Wettability alteration 1. Introduction 1 ACS Paragon Plus Environment
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Surfactants are widely employed in petroleum recovery applications owing to their favorable interfacial and rock-wetting characteristics. These chemical species function by adsorbing onto the crude oil-displacing fluid interfaces. With challenges faced during enhanced oil recovery (EOR) processes, surfactant systems require specific modifications in formulation to better suit reservoir needs [1-3]. Most often, a single surfactant system cannot provide all desirable attributes to achieve maximum oil recovery. Hence, mixed surfactants are applied in numerous field operations owing to superiority in terms of stability and physicochemical properties [4-6]. In recent years, evaluation of surfactant mixtures for EOR have gained rapid interest in the scientific community [7,8]. In this study, a favorable mixed surfactant system with beneficial traits and potentiality in EOR processes are introduced in an aqueous solution to derive synergistic interactions with the trapped crude oil and reservoir rock. Another important aspect of this study is cost-profitability and reduced environmental impact owing to less requirement of surfactant(s) in comparison to pure surfactant systems [9,10]. Focus is stressed on development of chemical compositions containing different surfactants in optimal dosage, which can be used as effective displacing fluids. In EOR processes, surfactant fluids recover residual oil molecules by IFT reduction [10-12]. Previous studies reported that IFT between oil and displacing fluid must decrease to ultra-low magnitudes for displacement of in-situ oil from pore spaces (otherwise trapped by capillary forces) of hydrocarbon-bearing reservoir rocks [13,14]. Surfactant monomers are adsorbed onto the oil-aqueous interfaces, with the hydrophobic tail groups orienting toward the oil phase and hydrophilic heads pointing toward the aqueous phase. This results in micelle/aggregate formation, which is an important transport conduit for crude oil movement [13,14]. Mixed surfactant fluids improve oil micellization ability of constituent surfactants by forming mixed micelles in dynamic flow systems [14-16]. Incorporation of ionic + non-ionic surfactants into aqueous fluids reduce the repulsive interactions among the charged polar head groups and favors improved adsorption efficiencies, which in turn, is responsible for improved oil extraction. Earlier studies showed that binary surfactant mixtures exhibit lower CMC values in comparison to single surfactants alone [16-19]. The neutral head groups in non-ionic surfactant molecules impart a blanketing effect on ionic surfactant head groups, thereby leading to the formation of condensed/denser micellar structures with greater stability [19]. In addition, mixed surfactants
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show improved compatibility in the presence of electrolytes, salts, etc. and are more thermally stable that are generally considered desirable characteristics of EOR chemicals. An accurate knowledge of adsorption and micellization processes occurring in mixed surfactant species is pivotal in developing optimal displacing fluid formulations. Rheological behavior of mixed surfactant systems is an important parameter, which has vast implications in crude oil mobilization in the presence of injected chemical phases [20-22]. Before oil is produced, it flows through large distances within the geological strata [21,22]. Optimized fluid injection reduces the mobility ratio values within pores to < 1 and, therefore, improves oil sweep in reservoir zones with low permeability [23]. The synergistic behavior among interacting surfactants is useful for understanding feasibility of movement of oil phases during tertiary recovery; as well as predict suitable physical, thermodynamic and applicative prospects of tailored EOR methodologies. The present article discusses the synergism between cetyltrimethylammonium bromide (CTAB) and Tween 60 / Polysorbate 60 in mixed state for effective application in EOR. Bulk micellization and adsorption properties of mixed surfactant species were studied initially. IFT behavior between crude oil and mixed surfactant solution phases was investigated under dynamic condition. Influence of polymer addition on surfactant solution(s) were studied by viscosity tests to identify flow behavior under varying shear rates. Viscoelasticity of polymer/mixed surfactant fluids were studied to gain a relative understanding of their adaptability and “flow-and-drive” characteristics under heterogeneous conditions. The ability to displace trapped oil under varying salinities is studied by a simulated sessile drop analyses. In this study, the spreading ability of injected chemical fluids is studied by dynamic progression of a water-wet film onto a crude oilsaturated rock surface. In summary, the objective of this project is to develop a cationic-nonionic mixed surfactant system with favorable oil displacement ability, with careful analyses of interfacial, wettability and bulk rheology investigations. 2. Experimental 2.1 Materials Cetyltrimethylammonium bromide, CTAB (with 98% purity) was purchased from Loba Chemie. Nonionic surfactant, Tween 60 or Polysorbate 60 (with 99.99% purity) in liquid form was purchased from Sigma Aldrich Limited, Germany. Sodium chloride (NaCl) salt was obtained from Rankem Chemicals. Crude oil employed for wettability alteration studies was obtained from ONGC (Ahmedabad Asset, India). It has an API gravity of 24.2° and viscosity of 38.7 3 ACS Paragon Plus Environment
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mPa.s at 303 K. Carboxymethylcellulose polymer was purchased from Loba Chemie and used as viscosity builder for mixed surfactant systems. 2.2 Electrical Conductometry and surface tensiometry Hanna HI-2003 conductivity meter was employed to determine the solution conductivity at different temperatures. A four-ring probe was dipped in mixed surfactant/single surfactant solution, and the readings were allowed to stabilize before measurement. After each experiment, the probe was cleaned and calibrated using buffer solution of known conductivity. Surface tension values were obtained using Du Noüy ring method. A platinum (circular) ring was immersed below solution surface and then slowly lifted. Surface tension of distilled water was also measured, as discussed in our earlier work [3]. The Harkins and Jordan correction geometry was used to account for ring effect. 2.3 Interfacial tension by spinning drop technique IFT between crude oil and displacing fluid phases were measured using spinning drop technique in SVT20 tensiometer (Dataphysics, Germany). In this study, the profile of an equilibrated crude oil drop under rotational motion was fitted and analyzed to obtain IFT value. Experimental studies were performed at different temperature conditions. 2.4 Viscosity measurements The viscosity of mixed surfactant solutions with varying polymer concentration and temperature were measured with varying shear rates. The non-Newtonian behavior obtained during viscosity measurements is described with the help of the Power Law model. 2.5 Oscillatory tests The viscoelastic behavior of mixed surfactant-polymer systems were investigated to check their relative abilities in heterogeneous systems, wherein “adaptability” and “flexibility are considered important attributes of oil displacing fluids. The storage modulus (G’) and viscous modulus (G’’) of aqueous systems were determined with varying angular frequencies. G’ indicates the amount of elastic energy, whereas G’’ is a measure of viscous energy to initiate flow. A crossover point is identified by careful analysis of these G’ and G’’ plots. At this frequency, the elastic and viscous character of analyzed fluids are measured as equal in magnitude.
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2.6 Rock wetting studies Rock-wetting characteristics of surfactant/polymer fluids onto crude oil-saturated sandstone rock surface(s) were measured using Contact Angle Goniometer (Model DSA25, Kruss, Germany) at different temperatures. Initially, the sandstone rock samples were fully immersed into crude oil and allowed to age for a period of thirty days. In this experiment, an accurately measured volume of proposed chemical fluids was dropped on the top surface of oil/intermediate-wet rock. Contact angles were measured at different time intervals using Young-Laplace fitting geometry in sessile drop mode. Wettability alteration results were further corroborated using image analyses of rock specimen at 200 μm magnification using Zeiss SteREO Discovery V20 (Modular) microscope. 2.7 Static adsorption tests Sand particles were added to surfactant/mixed surfactant solution with solid: liquid ratio 1:10. Thereafter, the mixture was stirred in horizontal shaker for 24 hours; and then allowed to centrifuge at 2000 rpm for 15 minutes to separate the supernatant fluid. The equilibrium surfactant in the aqueous phase was identified by interpolation/extrapolation method in plot analyses. All studies were conducted at 303 K. 2.8 Core flooding experiments Sandstone core (bulk volume 91.952 cm3) was initially immersed with brine (containing 1.0 wt. % NaCl) for a period of 72 h to determine the weights of core-rock specimen before and after saturation were measured to determine the porosity. Thereafter, the sample was placed inside core-holder in flooding apparatus (confining pressure in the range ~1000-1200 psi). Brine was flooded onto sandstone core-model to determine absolute permeability (k) value ~370 millidarcies (mD). Finally, core was injected with crude oil until irreducible water saturation state (Swi) was reached, and allowed to remain for some time-period to achieve an oil-saturated reservoir mini-model. During flooding studies, brine was initially introduced at the rate of 10 ml/h during secondary oil extraction process. Once water-cut exceeded 95%, core model was injected with chemical fluid (containing mixed surfactant, polymer) at 5 ml/h to produce additional crude oil. This was followed by chase water flooding in order to maintain oil recovery, until the last drop of crude oil can be recovered.
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3. Results and discussion This article covers a pre-screening analysis of micellization and adsorption parameters of pure and mixed surfactant systems to understand surfactant molecule behavior in aqueous phases. The ability of surfactant-based displacing fluids to reduce oil-aqueous IFT and simultaneously alter wettability nature of rock specimens were investigated. This provides benchmark to formulate/evaluate chemical injection fluids, and as well as optimizing physicochemical properties for crude oil recovery. The experiments performed are useful to formulate a strategy to identify effective displacing (fluid) slug compositions, particularly for non-ionic/ionic mixed surface-active fluid systems, for EOR application. 3.1 Adsorption behavior: single-surfactant and mixed surfactant system In both mixed surfactant and single surfactant systems, surfactants arrange themselves at the interface, such that the polar hydrophilic heads of surfactant molecules orient towards aqueous phase and the hydrophobic tail groups orient towards air. Head groups of cationic surfactants are responsible for electrostatic self-repulsion, wherein their bulky hydrophobic tails produce steric self-repulsion [24]. However, significant differentiation exists between the adsorption behavior of mixed surfactant and single surfactant fluids. In mixed surfactant systems, ion-dipole interactions in ionic-nonionic species are significant. Consequently, a synergism exists between the constituent species i.e. CTAB surfactant molecules and Tween 60 surfactant molecules, resulting in reduced electrostatic self-repulsion among cationic polar heads and steric selfrepulsion among non-ionic surfactant groups [25,26]. Therefore, the self-repulsive interactions are compensated by electrostatic or ion-dipole attractions, resulting in decreased electrostatic repulsion at the air-aqueous interface [25,26]. Therefore, mixed surfactant molecules exhibit better adsorption efficacy (or closer packing arrangement) as compared to pure surfactant solution. It is pertinent to note that decreased electrostatic repulsion of ionic groups as well as accommodation of non-polar tail groups is much more pronounced at the interface than a micelle within the bulk phase [26]. Fig. 1 shows an illustration of the surfactant adsorption behavior in CTAB and {CTAB + Tween 60} aqueous systems.
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Fig. 1. Adsorption behavior of (a) pure surfactant, CTAB; and (b) mixed surfactant {CTAB + Tween 60} systems at the air-aqueous interface.
3.2 CMC measurement by Electrical Conductivity studies The conductivity data for mixed surfactant compositions versus CTAB concentration at varying temperatures are depicted in Fig. 2. A break-point was observed, corresponding to intersection point of two straight lines for each system. This point of intersection is identified as the critical micelle concentration (CMC); wherein surfactant molecules begin to form micelles. The pre- and post-micellar regions represent two distinguishing linear regimes, formed due to changes observed in electrostatic repulsions between polar head charges from free state to agglomerated state in bulk aqueous solution. As per Williams et al. [27], the CMC was suitably measured at break-point of pre-micellar and post micellar plots. Analyses of mixed surfactant solution, containing varying CTAB surfactant + 0.0027% Tween 60 surfactant, at varying temperatures identified CMC values as 0.432 mmol/l (0.0157 wt. %) at 303 K; 0.581 mmol/l (0.0212 wt. %) at 323 K; and 0.854 mmol/l (0.0311 wt. %) at 343 K (in terms of CTAB concentration). This shows better micellization properties of mixed surfactant species as compared to pure CTAB solution, wherein CMC is identified as 0.900 mmol/l (0.0327 wt. %) at 303 K. CMC values are lower in mixed surfactant systems, than those in single surfactant systems. This is attributed to the decreased electrostatic repulsions among constituent surfactant molecules in mixed surfactant systems, resulting in faster micellization or aggregation behavior. Counter-ion binding as well as dissociation/ionization behavior among surfactant monomers helps in understanding the relative influence of surfactant concentration on micelle formation. At post-micellar state, mobility of dispersed structures also decrease as compared to surfactant molecules dispersed (without 7 ACS Paragon Plus Environment
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micelle) in non-aggregated state [27,28]. With rise in temperature, CMC decreases due to breakdown of surfactant-surfactant and surfactant-aqueous interactions and subsequent delay in micellization process [29]. The results of these experiments were corroborated with those of surface tension experiments, as described in next section.
200
Specific Conductivity (uS/cm)
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303 K 323 K 343 K
180 160 140 120 100
CMC
80 0.0
0.2
0.4
0.6
0.8
1.0
1.2
Surfactant Concentration (mM)
Fig. 2. Conductivity versus CTAB surfactant concentration for mixed surfactant (CTAB + Tween 60) solutions at different temperatures.
3.3 Measurement of CMC by Surface tensiometry Surface tension data for aqueous solution of mixed surfactant (cationic CTAB + nonionic Tween 60) at different temperatures are shown in Fig. 3. Surface tension initially decreases with increasing CTAB surfactant concentration in mixed surfactant aqueous phase due to gradual adsorption of surfactant (CTAB) molecules. Beyond CMC, surface tension values either remain constant or decrease slightly, showing that the rate of desorption exceeds the rate of surfactant adsorption. At CMC, vacant “accommodation” sites are completely saturated by surfactant molecules and micelle formation begins in the bulk phase [30]. Temperature rise delays micelle formation by slowing the rate of hydrophobic non-polar tail group entanglement. Therefore, micellization commences at higher concentrations at elevated temperatures, causing increase in CMC. Surface tension decreases with temperature due to increased availability of vacant sites along interfacial curvature [30,31]. Comparative analysis of surface tension and conductivity experimental results showed that results obtained from both studies are in close agreement with one another, as shown in Table 1. 8 ACS Paragon Plus Environment
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40
303 323 343
38 36
Conductivity (S/cm)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
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34
CMC
32 30 28 26 24 22 20 0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
1.1
1.2
1.3
CTAB concentration (mM)
Fig. 3. Surface tension versus CTAB concentration in mixed ionic/non-ionic systems at varying temperatures. Table 1. Comparison of CMC for mixed surfactant {CTAB + 0.0027% Tween 60} system at varying temperatures, determined using different measurement techniques. Temperature (K)
CMC obtained by conductivity
CMC from surface tension method
measurement (mmol/L)
(mmol/L)
303
0.432
0.464
323
0.581
0.560
343
0.854
0.824
3.4 Thermodynamics of mixed surfactant adsorption and micelle formation Surfactant molecules adsorb at air-solution interfaces, with the hydrophilic polar head group pointing toward the bulk aqueous phase. Though there is, a fair amount of deliberation pertaining to adsorption processes, surface tension data does provide a valid approach for thermodynamic effect and surface activity [32,33]. Earlier studies have shown that the adsorption coefficient (n) = 3 accounts for the two constituent surfactant molecules and counterion species [34,35]. In mixed surfactant species, n was taken as 3. Greater the surface excess concentration (Гmax) for mixed surfactant/pure surfactant systems, greater is the adsorption ability of constituting molecules and, subsequently, the interfacial energy barrier is decreased. This corresponds to improved oil displacing ability of injected surfactant fluids for EOR operations. The orientation and degree of packing of mixed surfactant molecules and their relative efficiency may be 9 ACS Paragon Plus Environment
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predicted from area occupied per molecule at interface (Amin). Lower the Amin value, greater is the number of surfactant species adsorbed at the interface. As temperature increases, the number of vacant sites available for adsorption increases, resulting in improved surface activity. Forces of adhesion between surfactant molecules and air are enhanced with temperature, contributing towards increased surface activity. Greater the degree of surfactant adsorption, smaller is the effective area (Amin) of surfactant molecule. The adsorption efficiency (pC20) and effectiveness ( ΠCMC) are additional parameters that further measure the activity of adsorbed surfactant species [36]. Gibbs energy change of adsorption (∆G0ads) and Gibbs energy change of micellization (∆G0m ) values are both negative, indicating ability of mixed surfactant molecules to adsorb as well as form micelles/aggregates. Higher magnitude of ∆G0ads is observed as compared to ∆G0m values, showing that adsorption process is more spontaneous as compared to micellization in aqueous mixed surfactant (CTAB + Tween 60) systems. Table 2 discusses the overall summary highlighting the surface activity and thermodynamic properties of adsorption and micellization phenomena in relevant fluid systems. The results of these pre-screening experiments and theoretical findings confirm that the studied mixed surfactant fluids possess favorable traits, which may be effectively optimized/employed for oil displacement processes during EOR. Table 2. Theoretical analyses of adsorption and micellization properties of single surfactant and mixed surfactant systems. System
T
α
β
ΠCMC (mN/m)
(K) Pure CTAB solution
Mixed {CTAB + Tween 60} solution
pC20
Γmax
Amin
∆G0mic
∆G0ads
(μmol/m2)
(Å2/molecule)
(kJ/mol)
(kJ/mol)
303
0.8784
0.1216
34.8
3.51
1.72
96.19
-19.00
-39.16
323
0.7981
0.2019
36.5
3.54
1.76
94.13
-22.29
-42.98
343
0.7452
0.2548
37.7
3.56
1.84
90.18
-24.72
-45.20
303
0.7946
0.2054
44.6
5.11
0.85
194.10
-23.31
-75.45
323
0.5695
0.4305
49.4
5.25
0.71
232.14
-28.76
-97.83
343
0.5583
0.4417
51.7
5.33
0.57
290.55
-29.19
-119.67
3.5 Mechanism of Oil displacement by mixed surfactant fluids In ionic/non-ionic surfactant mixtures, complex interactions exist between surfactant molecules and polymer chains, which influence the ability of the fluid to displace oil through pore space regions within reservoir formations. In single cationic surfactant systems, strong electrostatic 10 ACS Paragon Plus Environment
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repulsions exist between polar charged species. These forces are responsible for the formation of surfactant-stabilized oil micelles, encapsulated by polar head groups. For synergistic influence of surfactant mixtures, attractive interactions between the constituents must exist either because of electrostatic effect or Van der Waals forces [37,38]. In mixed systems, the polar uncharged species (non-ionic surfactant) orient themselves in-between cation head groups (CTAB surfactant) thereby improving adsorption density and subsequently improving interfacial activity at the oil-aqueous interfaces [39]. This improves micellar contact with neighboring water (solvent) molecules, favoring the generation and stabilization of mixed micelle/aggregate entities within the bulk solution phase. Reservoir salinity may cause a slight decrease in mixed surfactant solubility in solution, which causes a migration of surfactants to the interface. This, in fact, may result in improved oil-aqueous interfacial activity and subsequent oil mobility within porous rock formations [37,40]. Addition of polymer (carboxymethylcellulose) reduces the repulsive interactions between charged species owing to enhanced steric hindrance effect. As a result, the polymer coils expand to a lesser extent and a thicker encapsulation/deposition onto stabilized oil droplets are formed with a higher adsorbed amount of emulsifier molecules and improved ionic strength of mixed surfactant-polymer solutions [41,42]. Polymer chains attached to surfactantstabilized micelles also tend to elongate, resulting in a network structure with improved viscosity behavior [42]. Furthermore, the hydrogen bonding between –OH group of non-ionic surfactant and functional group of polymer molecules also affects mixed micellar arrangement. Stearic effects contribute to mixed micelle stabilization, in addition to the electrostatic effects previously present in bulk surfactant mixture. Fig. 4 illustrates the micelle/aggregate behavior and interacting forces among constituent molecules in mixed surfactant + polymer combination solutions. Major interactions present in polymer-mixed surfactant systems are electrostatic repulsions, hydrophobic interactions, hydrogen bonding and stearic hindrance effects [37,39]. On a molecular level, the (electrical) repulsive interactions between cationic charge species contribute toward enhanced micellar stability. Hydrophobic interactions is visualized as a “string of beads model” formed by associations between polymer chains and surfactant micelles [39,42]. Hydrogen bonding between non-ionic surfactant molecules and polymers contribute to strong bonding interactions that remain stable even under high shear and high temperature conditions [37,42]. Finally, the presence of elongated polymer chains shield a surface of a mixed micelle to that of another 11 ACS Paragon Plus Environment
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surface of a single surfactant/mixed surfactant micelle, leading to reduced coalescing ability. The above forces result in the formation of dense spatial network structure due to interactions among mixed surfactant micelles and polymer chains [39,41,43]. The hydrophobic volume of aggregates increase, allowing for effective mobility control applications. As a result, mixed micelles of cationic/non-ionic fluids constitute an effective driving media with improved physicochemical characteristics for chemical-induced oil recovery.
Fig. 4. Proposed schematic illustrating micellar arrangement and different interactions existing between molecules in {mixed cationic/non-ionic surfactant + polymer} based chemical fluids.
3.6 Oil-aqueous Interfacial tension studies Fig. 5 shows the IFT for crude oil-aqueous surfactant systems, obtained by spinning drop technique. A crude oil drop is allowed to rotate at high speeds, and thereafter profile-fitted to achieve a stable oil drop within a continuous aqueous single/mixed surfactant phase. Pure CTAB solution (at CMC) exhibit IFT of 0.185 mN/m at 303 K. Under dynamic condition, it is observed that mixed surfactants show better interfacial characteristics in comparison to those of single surfactant systems [44]. The oil-aqueous IFT for mixed surfactant system is observed to attain ultra-low values. Spinning drop profile analyses revealed IFT values of 6.59 × 10-2 mN/m, 3.12 × 10-2 mN/m and 9.74 × 10-3 at 303 K, 323 K and 343 K respectively. Electrostatic repulsions among polar heads of cationic surfactant solution is lower in case of mixed surfactants. The non12 ACS Paragon Plus Environment
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ionic surfactant (Tween 60) molecules orient themselves in between encapsulating cationic surfactant molecules, resulting in denser packing arrangement and significant reduction in IFT. With increasing temperatures, IFT reduces due to thinning of interfacial boundary and improved adsorption ability of (mixed) surfactant molecules onto the oil drop surface. Fig. 6 shows the oil drop profiles of both pure and mixed surfactant systems, along with their IFT values. For pure CTAB solution, a spherical oil drop with lesser oil-aqueous contact was obtained during spinning drop measurements. Mixed surfactant species cause greater stretching of the oil-aqueous interface, which subsequently improves surfactant activity and effectively reduces IFT. 0.22
Oil-aqueous Interfacial tension (mN/m)
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Pure CTAB solution at CMC Mixed CTAB + Tween 60 solution at CMC
0.20 0.18 0.16 0.14 0.12 0.10 0.08 0.06 0.04 0.02 0.00 303
323
343
Temperature (K)
Fig. 5. Oil-aqueous Interfacial tension for pure CTAB and mixed CTAB + Tween surfactant systems at different temperatures.
Fig. 6. Spinning drop images of stabilized oil drop in continuous aqueous surfactant solution containing CTAB (single surfactant system) and CTAB + Tween 60 (mixed surfactant system).
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3.7.1
Viscosity behavior
Mixed surfactant solutions show shear thinning or pseudoplastic behavior upto ~ 500 s-1 shear rates, as shown in Fig. 7. This behavior is characterized by flow behavior index (n) values of < 1. In polymer systems, surfactant molecules as well as in-situ soap molecules interact with one another and polymer hydrophobes to form stronger mixed micelle associations [45,46]. Hydrophobic interactions result in increased ionic strength of polymer chains attached to surfactant micellar structures, which leads to viscosity increase [45,46]. As a result, the structure of mixed surfactant micelles also undergo a favourable transition to a more elongated state due to polymer addition. Shear thinning or pseudoplastic character of surfactant-polymer formulations is considered beneficial in EOR studies. When injected fluid (mixed surfactant + polymer) moves far into reservoir, mobility control becomes an important aspect. Mixed surfactants exhibit improved oil displacing behavior in comparison to single surfactant systems. Furthermore, channelling of the injection fluid is reduced due to better viscosity achieved in mixed surfactant fluids. As expected, viscosity increases with polymer concentration due to entanglement of polymer chains with mixed micelles/aggregates. Values of R2 were obtained to be close to one, exhibiting that the experimental data can be well-fitted using the Power law model. Table 3 shows the parameter values in the shear thinning region. Values of consistency index (k) increase with carboxymethylcellulose addition due to change in molecular rearrangement of surfactant-polymer mixed micelle associations. In summary, rheological flow behavior of mixed surfactant solutions is enhanced considerably in the presence of carboxymethylcellulose polymer. 30.0
CTAB CTAB CTAB CTAB
27.5 25.0 22.5
Viscosity (mPa.s)
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+ + + +
Tween Tween Tween Tween
60 60 60 60
+ + + +
500 ppm CMC polymer 1000 ppm CMC polymer 1500 ppm CMC polymer 2000 ppm CMC polymer
20.0 17.5 15.0 12.5 10.0 7.5 5.0 2.5 0.0 0.1
1
10
100
1000
Shear Rate (s-1)
Fig. 7. Viscosity versus shear rate plots of different aqueous solutions containing CTAB + Tween 60 surfactants in the presence of polymer at 303 K. 14 ACS Paragon Plus Environment
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Table 3. Power law fitting constants for CTAB + Tween 60 + polymer solutions in pseudoplastic flow regime at 303 K. Composition of mixed surfactant/polymer aqueous solution at 303 K
k (Pa.sn)
n
R2
CTAB + Tween 60 + carboxymethylcellulose @ 500 ppm
0.0062
0.927
0.888
CTAB + Tween 60 + carboxymethylcellulose @ 1500 ppm
0.0133
0.902
0.988
CTAB + Tween 60 + carboxymethylcellulose @ 2000 ppm
0.0165
0.92
0.978
CTAB + Tween 60 + carboxymethylcellulose @ 2500 ppm
0.0189
0.914
0.981
3.7.2
Measurement of viscoelastic properties
Investigations on viscoelastic behavior is important to predict adaptability of displacing phase within subterranean hydrocarbon zones. Generally, petroleum-containing reservoirs are heterogeneous in nature, with varying permeability zones. Therefore, both elastic as well as viscous properties of chemical fluid are desirable in order to suitable displace crude oil existing in pore spaces with low permeabilities. As viscoelastic fluids, mixed surfactants show sufficient flexibility to enter in low permeability zones without losing their stability and physicochemical properties [47]. Fig. 8 shows the dynamic moduli versus angular frequency plots for different chemical fluid systems. With increasing frequencies, both G’ and G’’ increase, exhibiting significant viscoelasticity under dynamic conditions. The point of intersection between G’ and G’’ plots is identified as the point of crossover frequency from graph analyses. The crossover frequency marks the transition from liquid-like to solid-like behavior of mixed surfactant fluid systems. With increase in polymer concentration, crossover frequencies of chemical fluids were observed to decrease due to growth in mixed micellar structures. This network structure becomes more pronounced in the presences of polymer chain entanglements, which in turn, increases the relaxation time and tends to contribute towards faster elasticity response of mixed micelles in bulk aqueous phase [48,49]. In regions where G’ exceeds G’’ values, the elastic component of the analyzed mixed surfactant systems dominates over the viscous component. This shows that the surfactant micelles retain their molecular integrity even under reservoir conditions, wherein flow dynamicity and heterogeneity come into play [47,48]. In the presence of polymers, the viscoelastic property remains nearly unaltered showing sufficient oil carrying capability of mixed surfactant-polymer combinations through varying permeability regions [47,48]. Both ionic strength and polymer chain hydrolysis influence the viscoelastic character of chemical fluid combinations. Increased degree of polymer chain entanglement improves the ionic strength in 15 ACS Paragon Plus Environment
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bulk phase, resulting in formation of well-defined network [45,46,50]. As a result, the displacing fluid functions by plugging the high permeability zones that is difficult to surpass by subsequent fluid injections. Hence, the analyzed mixed surfactant containing fluids exhibit an adaptive and expanding ability, which is a promising trait in EOR applications.
Fig. 8. Viscoelastic profiles of mixed surfactant-polymer systems at 303 K.
3.8 Wettability alteration studies 3.8.1
Dynamic contact angle measurements
The wettability state of a reservoir depends on nature and mineral composition of rocks, crude oil properties, and fluid dynamics of inherent fluids present in the subsurface formation [51,52]. Investigations on sessile drop evolution were performed onto oil-wetted sandstone rock surface. Fig. 9 shows the dynamic contact angle values versus time graph-plots for different injection fluid systems. Initially (at time = 0), the displacing fluids form a sessile drop with contact angle values of > 90°, showing the oil-wet or intermediate-wet nature of rock. Both surfactant as well as polymer-surfactant systems exhibit favorable wetting characteristics, in which the wettability of rock is effectively altered to water-wet condition. The surfactant/polymer molecules interact with organic compounds in crude oil and slowly displace the oil molecules otherwise adsorbed onto rock surface [51,52].
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160 Pure Surfactant (CTAB) Mixed Surfactant {CTAB + Tween 60} Mixed Surfactant + 500 ppm CMC Polymer Mixed Surfactant + 1500 ppm CMC Polymer Mixed Surfactant + 2000 ppm CMC Polymer
140 120
Contact angle (
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100 80 60 40 20 0 0
100
200
300
400
500
600
700
800
900
Time elapsed (s)
Fig. 9. Dynamic contact angle values obtained during wettability experiment on oil-aged sandstone surface formed by analyzed chemical EOR fluids with elapse of time.
The mechanism of wettability alteration in mixed surfactant systems is slightly different in case of pure surfactant systems [52,53]. In CTAB system, the surfactant molecules interact with the negatively charged quartz rock surfaces and the oil molecules are effectively displaced and mobilized slowly, depending on the viscosity of displacing phase. In mixed surfactants, two forces come into play: interaction between surfactant molecules and rock surfaces; and viscous forces with the mixed surfactant fluids push the trapped oil phases on solid rock surfaces. The mixed surfactant systems show faster rate of contact angle reduction with time elapsed. Addition of polymers significantly improve the viscous forces but reduce the displacement rate of forward-moving displacing fluid. However, the polymer-surfactant induced EOR, also achieves strongly water-wet condition. Mixed surfactant fluid as well as mixed surfactant + polymer fluids can be employed as a potential chemical agent for oil displacement processes. Wettability alteration in oil-saturated rock systems involves three basic mechanisms: formation of ion-pairs from surfactant molecules and organic carboxylates, (b) ion-pair dissolution in oil phase and micelles, and (c) countercurrent brine imbibition of the brine owing to favorable capillary pressure [54]. The presence of cationic surfactant has the capability to effectively detach oil components from surface and change wettability to a more water-wetting state. Tween 60 molecules (being non-ionic in nature) orient themselves in-between the CTAB surfactant molecules onto sandstone rock, and further improve oil displacement ability by interacting with
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crude oil hydrophobic groups [55]. Fig. 10 depicts the dynamic evolution of gradually spreading mixed surfactant + polymer fluid onto oil saturated rock surfaces.
Fig. 10. Sessile drop images for {mixed surfactant + 500 ppm polymer} containing chemical solution as EOR fluid onto oil-wet sandstone rock at the end of 0 s, 60 s, 180 s, 300 s, 600 s, and 900 s.
3.8.2
Microscopic studies
Fig. 11 shows the results of microscopic study for sandstone at different stages of rock wetting. The initial oil-wet/intermediate wet state of rock is depicted in Fig. 11(a). Thereafter, the rock sample was saturated in brine for 72 hr followed by immersion in mixed surfactant-polymer fluid to further displace in-situ crude oil. Fig. 11(b) and Fig. 11(c) show the microscopic images of sandstone rock after water-flooding and chemical flooding respectively. Crude oil adsorbed onto rock surface is represented by dark regions in the figure. It is evident from analysis of Fig. 11(b) that some crude oil was displaced from rock surface during water flooding. Thereafter, crude oil phases adsorbed onto rock surface showed visual changes after saturation in chemical fluid solution. Fig. 11(c) proves that additional crude oil was further extracted from the rock surface due to favorable wettability alteration by {CTAB + Tween 60 + carboxymethylcellulose} displacing fluid. Hence, sandstone rock is favorably wetted by analyzed nixed surfactant fluids containing ionic surfactant/non-ionic surfactant/polymer dosage.
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Fig. 11. Microscopic images of sandstone rock at different stages: (a) Initial oil-saturated; (b) after water flooding; (c) after chemical {mixed surfactant + polymer} flooding.
3.9 Surfactant adsorption onto sandstone surfaces Fig. 12 shows the adsorbed amount of surfactant versus concentration plots obtained from adsorption tests. Amount of surfactant adsorbed per unit mass sand, q (mg/g) increases with increasing CTAB concentration for both single and mixed surfactant systems [56]. However, presence of non-ionic surfactant (Tween 60) molecules affect the degree of CTAB surfactant adsorption in mixed ionic/non-ionic surfactant fluids. Synergism between CTAB and Tween 60 molecules resulted in the accumulation of both cationic and non-ionic surface-active species onto sand surface, as well as improved the number of cationic surfactant molecules available for oil displacement in solution phase [57,58]. Furthermore, the repulsive forces existing between polar head groups of CTAB in bulk as well as interface is reduced by addition of Tween 60 molecules. Hence, some additional CTAB molecules previously existing on rock surface (in single surfactant fluid) are replaced by non-ionic species owing to steric hindrance effect. From careful analyses of adsorption data, it is found that CTAB adsorption onto sand surface decreases nearly four-fold times in mixed ionic/non-ionic surfactant fluids. Table 4 shows the values of fitting parameters for adsorption model studies. Both isotherms are observed to fit measured data with 19 ACS Paragon Plus Environment
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favorable R2 values. However, the Freundlich isotherm model shows better results than Langmuir model. Hence, a stacking arrangement of surfactant and/or mixed surfactant molecules is proposed at aqueous-rock interface owing to interactions of surfactant with sand particles, as well as among constituent surfactant species. Amount of CTAB surfactant adsorbed (mg/g) (mg/g)
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3.2
Single surfactant systems (CTAB) Mixed surfactant systems (CTAB + 0.0027% Tween 60)
2.8 2.4 2.0 1.6 1.2 0.8 0.4 0.0 0.5
1.0
1.5
2.0
2.5
3.0
CTAB concentration (mM)
Fig. 12. Adsorption density of CTAB onto sand surface for single-surfactant and mixed surfactant systems. Table 4. Langmuir and Freundlich model parameters for CTAB and {CTAB + Tween 60} fluid systems Chemical fluid
Adsorption model parameters Langmuir
Freundlich
KL
Qsat
χ2
R2
KF
1/n
χ2
R2
CTAB solution
1.26×10-5
0.836
0.053
0.922
0.913
0.839
0.039
0.944
CTAB + Tween
3.22×10-4
0.781
0.003
0.921
0.221
0.850
0.002
0.941
60 solution
3.10
Flooding performance: Secondary and Tertiary oil recovery efficacies
Oil displacement experiments were conducted by secondary and tertiary flooding onto oilsaturated sandstone cores. Fig. 13 shows oil recovery versus injection pore volume during different flooding stages, along with their saturation values. Conventional recovery by brine flooding yielded ~46% of original oil in place (OOIP). Still, a significant amount of oil remains trapped within reservoir pore-throats (particularly in heterogeneous layer) owing to different factors such as gravity, inertia and high capillary forces. When water-cut exceeded nearly 95%, 20 ACS Paragon Plus Environment
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chemical fluid containing an optimal composition of mixed surfactant + polymer was injected into the core. The chemical fluid pushed in-situ oil phases to form a forward-moving oil bank, as well as restricts backflow and entrapment of produced oil [59,60]. Chemical flooding was followed by second stage of enhanced oil recovery (EOR), wherein chase water was introduced with the objective of maintaining flow of mobilized oil. Mixed surfactant/polymer/chase water} flooding achieved ~20% of OOIP in sandstone core-flooding system. The flooding performance results of the analyzed chemical fluid formulation indicates its ability to extract trapped oil (otherwise unrecoverable by water flooding) by plugging high-permeability regions within pore spaces. 100 End of Flooding:
90
Cumulative oil recovery (%)
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Residual oil saturation sor = 24.88%
80
Oil recovery = 65.71%
70
Prior to Flooding studies:
60
soi = 72.58% Irreducible water saturation
Initial oil saturation
swi = 27.42%
50 40 30 20
Conventional water flooding
10
Chemical
Chase water flooding
Flooding
0 0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
5.5
Pore volume (PV) injected
Fig. 13. Secondary and tertiary oil recoveries obtained as function of pore volume (PV) in oil-saturated sandstone reservoir model.
4. Conclusions The paper primarily investigates the effectiveness of ionic/non-ionic mixed surfactant system for use as EOR fluid in mature reservoirs. The system comprises of an ionic surfactant (cetyltrimethyl ammonium bromide) and a non-ionic surfactant (polysorbate-type Tween 60). CMC value of mixed (CTAB + 0.0027% Tween 60) solution is found to be lower as compared to CTAB solution. This is attributed to better adsorption ability of surfactant molecules of non-ionic + cationic surfactant molecules onto the interface. Interestingly, CTAB fluids occupied
