Article pubs.acs.org/EF
Implementing New Microemulsion Systems in Wettability Inversion and Oil Recovery from Carbonate Reservoirs T. N. Castro Dantas,*,† P. J. Soares A,† A. O. Wanderley Neto,‡ A. A. Dantas Neto,† and E. L. Barros Neto† †
Department of Chemical Engineering and ‡Department of Chemistry, Federal University of Rio Grande do Norte, Natal-RN, Brazil ABSTRACT: Large investments in exploratory activities have stimulated new oil discoveries, generally in carbonate reservoirs. These reservoirs tend to be oil-wet, an aspect that impairs the mobilization of oil in the reservoir. However, different methods can be used to displace the oil. In particular, the wettability of the reservoir surface can be inverted to facilitate oil flow, thereby improving production rates. This paper aims to examine the influence of the inversion of rock wettability in the production and oil recovery from carbonate reservoirs using microemulsion systems. The study involved the use of three surfactants: a cationic one (CTAB), an anionic one (SDS), and a nonionic one (UNT90). Phase diagrams were constructed and microemulsion systems with specific compositions were tested in enhanced petroleum recovery assays. The results showed that CTAB presented a higher inversion potential of wettability when compared to the other surfactants. The microemulsions were effective in the recovery of the residual petroleum “in place” obtaining 76.92% for CTAB, 67.42% for SDS, and 66.30% for UNT90 systems.
1. INTRODUCTION The production of oil depends on the interaction of several factors such as capillary forces, interfacial tension among the fluids in the reservoir, permeability, porosity, wettability, and oil viscosity. Among the many parameters that affect the mechanism of oil displacement, one can highlight reservoir wettability. Monitoring this reservoir property is fundamental to understand the problems of multiphase flow, which can be encountered during the migration of oil from the rocks by conventional production mechanisms or in processes of enhanced oil recovery. Wettability is defined as the tendency of a fluid to be spread on or adhere to a solid surface in the presence of other immiscible fluids. Researches on wettability and its effects on oil recovery have established that there is a favorable wettability of the reservoir that enables maximum recovery of crude oil from a particular type of reservoir.1 The wettability of porous media is generally classified as homogeneous or heterogeneous. In a homogeneous environment, the entire rock surface is uniformly wetted by either water (brine) or oil (oil), according to its molecular affinity with these fluids. On the other hand, heterogeneous systems are formed when the rock surface have different affinities with water and oil, and distinct regions of the same rock can be wetted by water or oil.2 Standnes and Austad (2000) conducted tests with a limestone formation and found that certain surfactants, when added to brine, can change the wettability of the rock from oilwet to water-wet.3 In particular, Standnes et al. (2002) carried some studies using surfactants that were capable of improving the spontaneous imbibition of water in oil-wet carbonate rocks. In this study, the recoveries of oil from cores of an oil-wet reservoir using water solutions of a nonionic surfactant (alcohol ethoxylate, EA) and a surfactant cationic (C12TAB) were compared. In general, the efficiency of C12TAB was superior to that of EA with respect to spontaneous recovery of oil from the cores.4 © 2014 American Chemical Society
Drummond and Israelachvili (2002) measured the wettability of the mineral mica to crude oil (28° API) and brine. A surface forces apparatus was used to measure the interacting forces between each pair of surfaces (mica and crude oil, or mica and brine), in different conditions of pH and salinity. The surface forces were correlated with the results of the adsorption and wettability (contact angle) experiments under the same conditions of salinity and pH, concluding that the different species found in crude oil determined the wetting behavior.5 Zhang et al. (2006) studied the influence of the concentration of electrolytes, surfactants, and water−oil rates in recovering the wettability of carbonate rocks. These researchers concluded that the wettability of the limestone surface may be changed with alkaline/ionic systems.6 Wu et al. (2008) investigated the recovery of oil by using cationic surfactants. The group concluded that this class of surfactants is generally more efficient in the recovery of oil from limestone rocks. The results reported for oil recovery were consistent with the results of assessing of change in rock wettability.7 Tabary et al. (2009) performed assays to evaluate the improvement in oil recovery from fractured carbonate reservoirs by using a combination of sodium carbonate (Na2CO3) with a sulfated surfactant. The assays of spontaneous and forced imbibition were performed in oil-wet rocks. The tests were followed by procedures to establish the wettability data. The formulations containing surfactant and alkali were evaluated for performance in the soaking of oil correlating with interfacial tension. After comparing the solutions of alkali, with and without surfactant, the researchers concluded that the influence of surfactant on interfacial tension is the main factor Received: June 5, 2014 Revised: October 30, 2014 Published: November 3, 2014 6749
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Table 1. Surfactants Classification surfactant
classification
molecular formula
cetyltrimethylammonium bromide (CTAB) sodium dodecyl sulfate (SDS) lauryl alcohol with 9 ethylene oxide (EO) (UNT90)
cationic anionic nonionic
CH3(CH2)15N(CH3)3Br CH3(CH2)11OSO3Na CH3(CH2)11(CH2CH2O)9H
purity/suppliers ́ ≈ 99% Ê xodo Cientifica >99% Sigma >99% Oxiteno
in height and 4 cm in diameter were removed from the rock and used to measure the its porosity and permeability to water. 2.1.3. Oil and Brine. The crude oil used was from the Ubarana Field, located in the Potiguar Basin, Rio Grande do Norte, Brazil. The brine used as formation water was a solution of potassium chloride (KCl) at 2% weight in distilled water. 2.2. Determination of Microemulsion Regions in Phase Diagrams. Microemulsions containing cationic, anionic, or nonionic surfactants were obtained by titration of active substance (surfactant + cosurfactant) in water and oil phases. The Winsor systems were determined from the mass balance limit points of solubility, as described elsewhere.18 These pseudoternary diagrams were constructed by using butan-1-ol as cosurfactant, kerosene as oil phase, and a saline solution (NaCl 0.5 M), as water phase. The mass ratio between the surfactant and the cosurfactant (C/S) was two. 2.3. Effect of Salinity on Microemulsion Stability. The study of the influence of salt concentration in Winsor equilibrium systems was performed by choosing points within the microemulsion region (WIV) of diagrams obtained with each surfactant. Points with similar composition in each region were selected, and the original aqueous phase of the microemulsions was replaced with NaCl aqueous solution with concentrations of 0.1, 0.5, 1.0, and 2.0 M. 2.3.1. Points Selected from Salinity Study. After the study of the influence of salinity on the formation of microemulsions, all microemulsion points were selected, and measurements of viscosity, density, and wettability were performed. The compositions were chosen to determine how the amounts of water and surfactant affect the microemulsion properties. For the direct structures, the points had the following compositions: 2% surfactant; 4% cosurfactant, 92.8% NaCl aqueous solution (at different salinity levels), and 1.2% oil phase. The concentrations of NaCl chosen for these direct systems for each surfactants were: CTAB (0.1 and 0.5 M), SDS (0.5 and 1.0 M), and UNT90 (0.5 M). For bicontinuous microemulsion, the points had the following composition: 20% surfactant; 40% cosurfactant, 17% NaCl aqueous solution, and 23% oil phase, for ionic surfactants CTAB and SDS. In the case of the nonionic surfactant, the region of bicontinuous structures was closer to the vertex of C/S, and the following composition was selected: 26% surfactant; 52% cosurfactant, 9% NaCl aqueous solution, and 13% oil phase. The concentrations of NaCl for each systems in this domain were CTAB (0.1 and 0.5 M), SDS (0.1, 0.5, and 1.0 M), and UNT90 (0.1, 0.5, and 1.0 M). For inverse systems, the following composition was tested: 4% surfactant; 8% cosurfactant, 3% NaCl aqueous solution, and 85% oil phase. The effect of salinity was investigated only with the ionic surfactant systems, since no formation of Winsor IV systems was detected with UNT90 for any salt concentration in the oil-rich region of the phase diagrams. Therefore, for both CTAB and SDS systems, the salinity levels were 0.5, 1.0, and 2.0 M. 2.4. Physiochemical Characteristics. The viscosity and density of the fluids were determined as physiochemical properties. The viscosity measurements were carried with a Haake Mars equipment by applying a shear rate that ranged from 0 to 1000 s−1 at three different temperatures: 30 °C, 50 °C, and 70 °C. Densities were measured with a digital Anton Paar DMA4500N densimeter, at 25 °C. 2.5. Contact Angle Determination. The contact angle is the best method for measuring the wettability of surfaces and fluids. Under ideal conditions, however, this type of measurement is actually difficult to be implemented due to the intricate geometry of pores and the complexity of chemical fluids involved. The rock and fluid preparations were based on the methodology used by Standnes (2002), with some adaptations.4 The contact angles
for oil recovery, being responsible for favorably changing the wettability.8 Austad et al. (2011) studied the recovery of oil from the cores of a limestone reservoir by forced displacement. The study focused on the use of different brines and types of oil with different acidity indices. It verified that, by injecting distilled water in the core, small quantities of anhydrite (CaSO4) were detected in the rock. It was proposed that the effects of low salinity in enhanced oil recovery (EOR) can be obtained in carbonates due to the presence of anhydrite. The recovery of oil was low and ranged between 1 and 5% of the original oil in place (OOIP) when injected first with formation water (FW) of high salinity (208 940 ppm) and, then, with FW 100 times diluted, or seawater from the Gulf (GSW), 10 times diluted because of the low concentration of anhydrite in the material of the core. This possibly affected the process of wettability adjustment, which is also dependent on the temperature and salt concentration.9 Sharma and Mohanty (2013) studied the inversion of wettability of a carbonate rock from mixed-wet toward waterwet at high temperature and high salinity, using three types of surfactants in diluted concentrations. Contact angle measurements on aged calcite plates were performed, and spontaneous imbibition experiments were conducted on field cores. It was observed that most surfactants were aqueous-unstable by themselves at harsh conditions of temperature and high salinity. The results show that dual-surfactant systems are suitable for wettability alterations at high temperature with high salinity reservoirs, because of aqueous stability, and a mixture of cationic and nonionic surfactants in diluted concentration can recover as much as 70 to 80% of the oil in place by spontaneous imbibition.10 It is widely know that surfactants have favorable characteristics that allow them to interact with the fluids. These substances also have the ability to change the interfacial tensions and the wettability of the rock to provide better conditions for oil displacement. These intrinsic qualities of surfactants have motivated researchers to develop many studies in this area.1,11−17 Based upon these facts, this study proposed to survey the influence of the wettability of the rock in the production and recovery of oil from carbonate reservoirs, using direct, inverse, and bicontinuous microemulsion systems. The assays were carried out with three types surfactants, one cationic, one anionic, and one nonionic, to prepare different microemulsion systems. The characterization of the fluids involved and the rock was then determined in a range of experimental conditions.
2. EXPERIMENTAL METHODOLOGY 2.1. Materials. 2.1.1. Surfactants. The selected surfactants belong to three classes: cationic, anionic, and nonionic. Their characteristics are listed in Table 1. 2.1.2. Carbonate Rocks. The limestone used in the study was extracted limestone rocks from the Jandaira Formation, which is located in the State of Rio Grande do Norte, Brazil. The rock was calcined at 250 °C for 6 h. Cylindrical cores with approximately 5 cm 6750
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Figure 1. Schematic representation of the reservoir simulator: (a) displacement fluid; (b) pump; (c) fluids cell of injection; (d) transducer; (e) compressor; (f) greenhouse; (g) holder; (h) collector of fluids injected; (i) fluid injection line; (j) output line of fluids; (k) pressure gauge. of the limestone rock were determined as follows. Initially, pieces of limestone were broken into fine particles and were then separated by screening. Particles with 270 Mesh were separated, and then, tablets weighing approximately 0.40 g were prepared with the aid of a press. The tablets were placed in a closed container with oil from the Ubarana Field and aged for 48 h at 50 °C. After this period and cooling to ambient temperature (27 °C), the tablets were washed quickly with toluene and n-heptane and dried at ambient temperature. The tablets were subsequently soaked in microemulsions for 30 min at ambient temperature and let to dry naturally. The tablets were finally placed horizontally, and a drop of aqueous KCl solution at 2% water was carefully transferred to the surface using a Kruss K100C Tensiometer to measure the contact angle. 2.6. Advanced Oil Recovery. The recovery assays consisted of a capacity study of recovery of light oils by microemulsions from carbonate reservoirs. The Confinement System for Hydrostatic Tests in Porous Media (Figure 1)19 was use in enhanced oil recovery (EOR) experiments to determine the recovery efficiencies by the conventional (brine, KCl solution) and special (microemulsion) methods. A temperature of 30 °C and confinement pressure of 1000 psi was applied in all tests. For the simulation assays, the rocks were cut in a cylindrical shape with 4.0 cm of diameter and 5.0 cm of height. The recovery assays were set out in 4 steps. In the first phase, brine (KCl solution to 2% weight) was injected through the core under a constant flow of 0.5 mL·min−1. In the second step, oil was injected under a constant flow of 0.5 mL·min−1. In the third step, the recovery procedure started, whereby brine was injected again with the aim of recovering oil by the conventional method of recovery. During the fourth phase, the microemulsion was injected as a method of advanced recovery. Samples were collected over time, and the volumes of oil recovered were quantified in order to calculate the percentage of recovery by using this enhanced technique. Figure 1 depicts the reservoir simulator.
region in the phase diagrams, mainly in the water-rich region, were selected. The constructed diagrams showed all Winsor regions, forming both direct, oil-in-water (O/W) and inverse, water-in-oil (W/O) microemulsions. This is an interesting aspect of the investigated formulations, which allows their adaptable use in real applications, in case different or changing polarities are encountered in the fields. The diagram for SDS showed the largest microemulsion region, and Winsor II systems (inverse microemulsions with excess water) are more abundant with UNT90. 3.1.1. Effect of Salinity on Microemulsion Stability. Salinity can affect the stability of microemulsions, and this was assessed by choosing specific points within regions corresponding to direct O/W, inverse W/O, and bicontinuous microemulsions of three phase diagrams. It was possible to assess surfactant behavior under different salt concentrations, namely, 0.1, 1.0, and 2.0 M, depending on the microemulsion structure. The composition of the points in the direct microemulsion region was the same for the three surfactants, aiming to evaluate the effect of the increase in salt concentration in microemulsion systems with ionic surfactants of different character. The microemulsion systems had the following composition, in mass: 2% surfactant, 4%, cosurfactant, 92.8% NaCl, and 1.2% kerosene. For the bicontinuous microemulsions, which have similar amounts of water and oil, the compositions depended on the type of surfactant. Microemulsions formed with CTAB or SDS comprised 20% surfactant, 40% cosurfactant, 17% NaCl aqueous solution, and 23% kerosene. However, the nonionic UNT90 can generate microemulsions only when a relatively higher amount of active matter is used, that is, higher amounts of surfactant and cosurfactant were required. As a result, the composition selected for UNT90 systems was 26% surfactant, 52% cosurfactant, 9% NaCl aqueous solution, and 13% kerosene. The points chosen within the region of inverse microemulsion droplets had the following composition: 4% surfactant, 8% cosurfactant, 3% NaCl, and 85% kerosene. However, no microemulsions were formed with UNT90 systems in the W/O region.
3. RESULTS AND DISCUSSION 3.1. Preparation of the Microemulsion Systems. The microemulsion systems used in this work were originally investigated by Roberto et al. (2013), who constructed appropriate pseudoternary phase diagrams.18 Three different surfactants (CTAB, SDS, and UNT90) were tested. Butan-1-ol was used as cosurfactant, kerosene was the oil phase, and a 0.5 M solution of NaCl was used as the aqueous component of the microemulsions. Systems that presented a larger microemulsion 6751
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In the UNT90 system in the region of direct structure, microemulsions (Winsor IV) were obtained with only 0.5 M of salt. For other concentrations, Winsor I was the preferred system obtained. This behavior is explained by the fact that the amount of saline charges is still too low to cause any shielding effect capable of stabilizing the aggregates. In turn, it maintains the repulsion of ethoxylate groups that are facing outside the droplets, as this part of the structure of the surfactant presents unpaired electrons. When one increases the salt concentration to a sufficient amount (0.5 M), the repulsive effect of surfactant monomers is reduced and WIV systems are formed. However, for salt concentrations above this value, a dense cloud of charges is formed, decreasing surfactant solubility in water medium and impairing the solubilization of the hydrophobic oily phase. As a result, it is expelled from the clusters and Winsor I systems are formed. For the bicontinuous microemulsion, the UNT90 showed similar behavior of ionic surfactants, because are formed microemulsions in concentrations of 0.1, 0.5, and 1.0 M. The appearance of WII systems was observed only with the highest concentration of NaCl (2.0 M). Also, phase transition occurred from WIV to WII systems when the salt concentration was increased. In this case, inverse droplets were formed because the increase in salinity affected hydrophilicity of the surfactant and reduced its solubility. Consequently, the surfactant molecules tended to “protect” themselves, and WII systems were formed. 3.2. Rheological Study. The rheological fluid displacement can be directly related with the efficiency of oil recovery. Figure 2 shows the relationship between the shear tension and the
For the CTAB systems, the microemulsion region was maintained at NaCl concentrations of 0.1 and 0.5 M. On the other hand, as the salt concentration increases to 1.0 and 2.0 M, Winsor II biphasic systems prevail. Similarly with bicontinuous structure, Winsor IV systems are dominant for low salt concentrations (0.1 and 0.5 M), but with 1.0 and 2.0 M, Winsor I systems are preferably formed. For inverse microemulsion, Winsor I systems are formed with the lowest salt concentration (0.1 M), and as this increases to 0.5, 1.0, and 2.0 M, Winsor IV systems are more favorable. For direct SDS systems, the minimum and maximum amounts of NaCl favor the formation of Winsor II systems. Microemulsions (WIV) were stable for intermediate salinity levels (0.5 and 1.0 M). For bicontinuous systems prepared with SDS, a similar behavior to that of the CTAB was observed, in that WIV systems were preferably formed at lower salinity levels and Winsor I systems were formed at higher salt concentrations. When inverse microemulsions are tested, the presence of salt at lower levels favor the formation of Winsor I systems, while WIV systems are generated when salt concentration increases (0.5, 1.0, and 2.0 M). It was possible to observe that there occurs a phase transition from WIV to WII with direct CTAB structures when salt concentration increases. This behavior is due to the high amount of cations and anions that compete with the polar moiety of surfactant when dissolved in the medium. Nevertheless, during the transition the hydrophilic capacity of the surfactant is reduced, thereby impairing water solubilization and forming biphasic Winsor II systems, which comprise water excess. With the SDS, the formation of Winsor II systems was observed at low salt concentrations. At this increased, the transition to Winsor IV occurred and was then shifted back to Winsor II at even higher salinity levels. The explanation for such behavior is due repulsion between the surfactant monomers, which naturally destabilizes the droplets and dissolves them. When a small quantity of salt is added, a shield is formed between the negative charges of the polar part of surfactant. At that stage, positive charges are transferred by the sodium present as free species in the medium, enabling microemulsion formation. However, upon increasing the salt concentration, the shielding effect is reduced. Electrostatic repulsion remains due to the large amount of ionic species in the medium, further destabilizing the system and leading to the Winsor II systems. Both CTAB and SDS had a similar behavior as bicontinuous structures, in that the addition of salt promoted a transition from WIV to WI. This change occurred because the increase in salt concentration in the medium rendered surfactant’s polar part able to solubilize the reduced amount of water, preferentially forming of inverse droplets, and releasing excess oil with the dissolution of salt. Their behavior was also similar when inverse formulations where prepared, that is, there was a change from WI to WIV systems with the increase of salt concentration. The lowest amount of salt in the solution was not sufficient to reduce electrostatic repulsion of the polar part of the surfactant, hindering the solubilization of the excess oil phase. When the concentration of salt is relatively higher, the water medium tends to be saturated by positive and negative charges, which facilitates the uptake of the water phase by the droplets, thereby promoting the formation of inverse microemulsions.
Figure 2. Relationship between the shear rate and shear tension with Ubarana Oil samples at 30 °C, 50 °C, and 70 °C.
shear rate of the Ubarana Field samples at three temperatures: 30 °C, 50 °C, and 70 °C. At these temperatures, the apparent viscosities of these oil samples were 14.94, 8.63, and 5.33 cP, respectively. According to Figure 2, the oil can be considered a Newtonian fluid, in the range of the shear rate from 0 to 1000 s−1, because the ratio between the shear tension and shear rate is constant. The viscosity values obtained were considerably low and consistent with the expected values, corresponding to highly fluid, light oil samples. Obviously, the viscosity also decreases 6752
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Figure 3. Relationship between the shear rate and the shear tension at 30 °C, 50 °C, and 70 °C for direct microemulsions with (a) CTAB, (b) SDS, (c) UNT90, all with 0.5 M NaCl solution as water phase.
with increasing temperature, as is the case all Newtonian fluids, which are affected mainly by temperature and pressure. Figures 3, 4, and 5 shows the relationship between the shear tension and the shear rate of direct, bicontinuous, and inverse microemulsions, respectively, as a function of temperature. Because the rheological behavior of fluids from regions that correspond to the same structure were rather similar, that is, the concentration of salt in the microemulsion did not cause much effect, the assays were based on the same diagram that was selected for all surfactants, with 0.5 M NaCl solution as water phase. As one can observe in Figures 3, 4, and 5, the relationship between shear tension and shear rate is not typically constant. Therefore, the microemulsions analyzed are considered nonNewtonian fluids. In fact, in most case, the fluids used in the oil industry do not display Newtonian behaviors. The rheological model widely adopted for these fluids is the Ostwald de Waale model (Power Law). In this model, two specific rheological parameters are presented: the behavior index (n) and the consistency index (K). If n > 1, the fluid is dilating; n < 1, the fluid has a pseudoplastic behavior; and n = 1, the fluid is Newtonian. In Table 2, the values of apparent viscosity of the direct microemulsions are listed together with Ostwald’s parameters considering the temperatures established for this study. By analyzing the value of the behavior index (n > 1) for the shear rate in the range of 250−1000 s−1, one can observe that direct microemulsions deviate from the Newtonian behavior, behaving as dilating fluids. As the shear rate increases, the volume and resistance to shear are enhanced. The growth in viscosity with the shear rate can be attributed to rheological dilatancy.
Table 3 shows the values of apparent viscosity as a function of temperature for bicontinuous microemulsion, for which the behavior index indicates that these fluids are pseudoplastic (n < 1). Also, the viscosity of these fluids decreases with the increasing shear rate. Table 4 shows the values of apparent viscosity as a function of temperature for the inverse microemulsion systems, which behaved similarly to direct microemulsions. The value of the behavior index was higher than 1. Variation of shear rate within the same range indicated that these microemulsions behaved as dilating fluid. This study concluded that the viscosity of the selected microemulsions showed a small variation for different systems, with little impact on advanced recovery. The rheological results shown in Tables 2, 3, and 4 confirm that the viscosities of all microemulsions are lower than those of the original oil. These viscosities decreased with the increase in temperature and were little affected by the salt concentration. 3.3. Density. Density is one of physical properties used to define the main characteristics of oil samples, by which it is possible to calculate their API grade, which is a way of expressing the relative density of the oil or its derivates. The density of the oil used in this work was 0.8582 g/cm3, which corresponds to an API degree of 33.23. According to the American Oil Institute, the oil used was characterized as light because its API was higher than 30. This oil was chosen due to its similarities with oil samples found in the Brazilian Presalt layer, where the reservoirs are formed mainly by carbonate rocks. The densities of all microemulsion systems investigated in this work are listed in Table 5. It can be seen that all values are close to that of pure water (0.99820 g/cm3, at 25 °C) for direct microemulsions. For oil-rich microemulsions, the results 6753
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Figure 4. Relationship between the shear rate and shear tension at at 30 °C, 50 °C, and 70 °C for bicontinuous microemulsions: (a) CTAB, (b) SDS, and (c) UNT90, all with 0.5 M NaCl solution as water phase.
Figure 5. Relation between the shear rate and shear tension at at 30 °C, 50 °C, and 70 °C from inverse microemulsions: (a) CTAB and (b) SDS, all with 0.5 M NaCl solution as water phase.
are similar to the density of kerosene (0.7975 g/cm3, at 25 °C). In the case of bicontinuous microemulsions, whose structures vary between those of O/W and W/O systems, intermediate density values were observed, ranging between those of pure kerosene and water. 3.4. Rock Wettability Study by Contact Angle Measurements. Aiming to verify the potential of different microemulsions in changing the wettability of the limestone rock from oil-wet to water-wet, measurements of contact angle were performed using neutral limestone as mineral surface. The rock was prepared according to the procedure described in Section 2.5. Table 6 shows the measured values for the contact
angle formed on the drop of brine (2% KCl) deposited on the rock, both with and without microemulsion treatment. In all cases, even without any treatment with microemulsion, the contact angle did not exceeded 90°, confirming that the rock used is not oil-wet. Despite this result, the angle value is in accordance with the literature classification (75−120°)20 for neutral wettability. The experiment enable to conclude that, after treating the rock with different microemulsions, the contact angle was lowered significantly when the rock was treated CTAB systems. For anionic and nonionic systems, even though the limestone wettability was modified, higher contact angle values were reported. The values presented in Table 6 6754
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Table 2. Apparent Viscosity of the Direct Microemulsions at 30 °C, 50 °C, and 70 °C system CTAB NaCl 0.1 M
temp. (°C) 30 50 70
CTAB NaCl 0.5 M
30 50 70
SDS NaCl 0.5 M
30 50 70
SDS NaCl 1.0 M
30 50 70
UNT90 NaCl 0.5 M
30 50 70
Ostwald’s params. (n, K) n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K
1.453, = 1.31.10−4 1.351, = 2.17.10−4 1.329, = 2.09.10−4 1.360, = 2.62.10−4 1.373, = 1.92.10−4 1.377, = 1.68.10−4 1.405, = 1.85.10−4 1.404, = 1.55.10−4 1.395, = 1.42.10−4 1.359, = 2.7.10−4 1.304, = 1.56.10−4 1.299, = 2.89.10−4 1.374, = 2.18.10−4 1.418, = 3.06.10−4 1.427, = 1.11.10−4
Table 3. Viscosity of the Bicontinuous Microemulsions at 30 °C, 50 °C, and 70 °C
apparent viscosity (1000 s−1) (cP)
system
3.16
CTAB NaCl 0.1 M
temp. (°C) 30
2.36
50
2.24
70 CTAB−NaCl 0.5 M
3.25
30
2.53
50
2.28
70
3.05
SDS NaCl 0.1 M
30
2.55
50
2.18
70
3.15
SDS NaCl 0.5 M
30
2.81
50
2.29
70
3.00
SDS NaCl 1.0 M
30
2.51
50
2.14
70 UNT90 NaCl 0.1 M
30 50
will be discussed in sections 3.4.1 and 3.4.2 separately, focusing on the reversal of wettability with respect to the nature of the ionic surfactant, and the influence of salinity. 3.4.1. Wettability As a Function of the Surfactant’s Ionic Character. Regarding the nature of ionic surfactants, all microemulsions tested were able to change the rock wettability from neutral to water-wet. The cationic surfactant had a higher potential to change the rock wettability to water-wet than the anionic and nonionic surfactants. Figure 6 shows images obtained with the equipment, indicating the contact angle on the rock treated with direct microemulsion systems and with the drop of KCl solution, 2% by weight. The selected microemulsions had the same composition: 6% cosurfactant + surfactant, 92.8% aqueous phase, and 1.5% oil phase. With this assay, it was possible to examine the inversion in rock wettability due to the surfactant structure. Initially, the rock surface was typically hydrophobic, only slightly water-wet. The possible mechanism for imbibition of the microemulsion on the rock can be described as an interaction between the surfactant monomers and negatively charged organic carboxylates that are adsorbed from crude oil. It is suggested that pairs of ions are formed that remove the carboxylates by making the surface water-wet, thereby displacing the oil.21 By analyzing Figure 6a, one can observe that, without microemulsion treatment, the KCl drop deposited on the surface of the rock presented a high contact angle value (87.2°) due to the strong interfacial tensions between the water/oil/ rock interfaces, a clear indication that the rock is typically oilwet. After treatment of the limestone rock with the microemulsion systems, there was a reduction in the interfacial
70 UNT90 NaCl 0.5 M
30 50 70
UNT90 NaCl 1.0 M
30 50 70
Ostwald’s params. (n, K) n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K
0.998, = 4.92.10−3 0.97, = 3.76.10−3 0.860, = 5.11.10−3 0.990, = 5.28.10−3 0.982, = 3.56.10−3 0.882, = 4.51.10−3 0.985, = 5.83.10−3 0.977, = 3.91.10−3 0.893, = 4.57.10−3 0.974, = 6.53.10−3 0.964 = 4.39.10−3 0.613, = 2.52.10−2 0.978, = 6.40.10−3 0.966, = 4.48.10−3 0.663, = 1.95.10−2 0.866, = 1.26.10−2 0.952, = 4.41.10−3 0.7912, = 7.68.10−3 0.979, = 5.97.10−2 0.955, = 4.37.10−3 0.848, = 5.69.10−3 0.984, = 5.86.10−3 0.966, = 4.14.10−3 0.840, = 5.97.10−3
apparent viscosity (1000 s−1) (cP) 4.87 3.07 1.95 4.94 3.16 1.99 5.19 3.33 2.19 5.47 3.44 1.75 5.53 3.54 1.96 5.03 3.17 1.81 5.17 3.21 2.00 5.27 3.28 1.97
tension between the water/oil/rock interfaces, and consequently, the rock wettability was reversed from oil-wet to waterwet. Contact angle values as low 27.8%, 31.9%, and 37.8% were observed when treating the surface with CTAB, SDS, and UNT90 microemulsion, respectively. The surfactant’s chemical structure has a significant impact on the ability to modify the limestone wettability. In general, one can perceive that ionic surfactants show better results than nonionic surfactant. It is noticeable that the cationic surfactant has a much greater potential to modify the limestone wettability due to a much more intense positive charge. This is particularly important when examining adsorption at the water/oil/rock interface, where the nonpolar part is oriented to the interior of the rock and the polar part in contact with water at the rock/ fluids interface, making the rock water-wet and displacing the 6755
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Table 6. Contact Angle Values Measured from Each Systema
Table 4. Viscosity of the Inverse Microemulsions a 30 °C, 50 °C, and 70 °C system CTAB NaCl 0.5 M
temp. (°C) 30 50 70
CTAB NaCl 1.0 M
30 50 70
CTAB NaCl 2.0 M
30 50 70
SDS NaCl 0.5 M
30 50 70
SDS NaCl 1.0 M
30 50 70
SDS NaCl 2.0 M
30 50 70
Ostwald’s parameters (n, K) n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K n= K
system
apparent viscosity (1000 s−1) (cP)
1.221, = 6.41.10−4 1.339, = 2.62.10−4 1.282, = 3.19.10−4 0.990, = 5.28.10−4 1.345, = 2.44.10−4 1.250, = 4.00.10−4 1.272, = 4.46.10−4 1.367, = 4.28.10−4 1.151, = 7.75.10−4 1.231, = 5.93.10−4 1.269, = 3.66.10−4 1.154, = 7.59.10−4 1.260, = 4.85.10−4 1.391, = 3.46.10−4 1.307, = 1.24.10−3 1.289, = 3.91.10−4 1.303, = 3.09.10−4 1.098, = 1.03.10−3
limestone rock
2.96
limestone rocks treated with different microemulsions
2.73 2.25 2.92 2.66 2.26 2.93 2.42 2.21 2.94 2.83 2.16
contact angle
without microemulsion treatment
87.2
MD−CTAB−NaCl 0.1 M MD−CTAB−NaCl 0.5 M MD−SDS−NaCl 0.5 M MD−SDS−NaCl 1.0 M MD−UNT90−NaCl 0.5 M MB−CTAB−NaCl 0.1 M MB−CTAB−NaCl 0.5 M MB−SDS−NaCl 0.1 M MB−SDS−NaCl 0.5 M MB−SDS−NaCl 1.0 M MB−UNT90−NaCl 0.1 M MB−UNT90−NaCl 0.5 M MB−UNT90−NaCl 1.0 M MI−CTAB−NaCl 0.5 M MI−CTAB−NaCl 1.0 M MI−CTAB−NaCl 2.0 M MI−SDS−NaCl 0.5 M MI−SDS−NaCl 1.0 M MI−SDS−NaCl 2.0 M
25.1 27.8 31.9 55.6 37.8 14.6 28.3 54.1 28.8 19.8 58.3 53.0 35.6 18.0 24.3 26.1 50.8 56.1 60.9
a
DM: Direct microemulsion. BM: Bicontinuous microemulsion. IM: Inverse microemulsion.
2.93 2.17 2.07 2.89 2.51 2.04
Table 5. Density (ρ) of the Microemulsioned Systems at 25 °C direct microemulsion
bicontinuous microemulsion
inverse microemulsion
system
ρ (g/cm3)
CTAB−NaCl 0.1 M CTAB−NaCl 0.5 M SDS−NaCl 0.5 M SDS−NaCl 1.0 M UNT90−NaCl 0.5 M CTAB−NaCl 0.1 M CTAB−NaCl 0.5 M SDS−NaCl 0.1 M SDS−NaCl 0.5 M SDS−NaCl 1.0 M UNT90−NaCl 0.1 M UNT90−NaCl 0.5 M UNT90−NaCl 1.0 M CTAB−NaCl 0.5 M CTAB−NaCl 1.0 M CTAB−NaCl 2.0 M SDS−NaCl 0.5 M SDS−NaCl 1.0 M SDS−NaCl 2.0 M
0.99597 1.00859 1.01061 1.02826 1.00950 0.87322 0.87506 0.88734 0.88960 0.89126 0.87147 0.87257 0.87266 0.80477 0.80532 0.80575 0.80641 0.80692 0.80759
Figure 6. Drop of 2% KCl aqueous solution deposited on the surface of the limestone: (a) before imbibition in microemulsions, and after soaking in microemulsions prepared with (b) CTAB, (c) SDS, and (d) UNT90.
3.4.2. Wettability As a Function of Salt Concentration in the Microemulsion. The effect of salt concentration in the microemulsion on the inversion of rock wettability was also investigated by means of contact angle measurements, with direct, bicontinuous, and inverse microemulsion systems. The procedure adopted was the same as the one discussed above (section 3.4.1), and the results were also presented in Table 6. These data are show as graphs in Figure 7 for a better understanding of the influence of salinity on the contact angle. By analyzing Figure 7a, one can observe that the wettability of the rock treated with different microemulsion systems, with different salinity levels, is highly dependent on the type of microemulsion (direct, bicontinuous, or inverse), and the amount of salt in the formulation. For samples treated with CTAB, the contact angle ranged between 14 and 28°; for SDS systems, it varied between 32 and 61°, and for UNT90 contact
oil. This potential of reversal in wettability decreases in the following order: CTAB > SDS ≈ UNT90. 6756
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Figure 7. Effect of salinity on the contact angle formed on limestone treated with (a) direct, (b) bicontinuous, and (c) inverse microemulsions.
angles between 38 and 53° were observed (Table 6). The wettability could be assessed by the values of contact angle, showing that direct and inverse microemulsions exhibit similar results. The salinity has a strong influence on the behavior of the aggregates and also affects the wettability. In general, an increase in the contact angle with the increase in salt concentration is noticeable when direct and inverse structures are involved. However, it is possible to see that inverse microemulsions show better wettability results. The adsorption process between the rock and the oil is much more efficient, because of the oil-continuous phase of these microemulsions. Thus, there are favorable interactions between the oil phase and the oil contained in the rock due to their chemical similarities, which favor the reduction of the interfacial tension and, consequently, enhance oil displacement from the rock pore. The ionic surfactants tend to bind more in the rock when the salt concentration is increased. Due to repulsive forces with equivalent magnitudes, the surfactant molecules tend to occupy a larger area at the surface, and the addition of small amounts of water-soluble salts can decrease this repulsion and increase the coating of the surface by the surfactants. The same does not occur with nonionic surfactants, as they do not have any charges in the polar moiety and are not affected by electrostatic repulsions that separate the surfactants molecules. An analysis of Figure 7b for bicontinuous microemulsions shows that the increase in salinity decreases the contact angle of the brine drop on the rock surface in the case of SDS and UNT90 but increases that for CTAB. In this type of microemulsion, it is possible that the increase in salt concentration affects differently each surfactant system. In the case of microemulsions with CTAB, the salt species may have hindered the adsorption process. For SDS, they reduced the electrostatic repulsion between the surfactant head groups,
enhancing the oil desorption process. Finally, for UNT90 systems, the amounts of salt were not sufficient to reduce surfactant solubility in water, when compared to the concentration of surfactant used, and the adsorption process was not significantly affected. According to Figure 7c, the inverse microemulsions showed similar behaviors to the direct microemulsions. The increase in salinity reduced the wettability of the rock with water, influencing more strongly the anionic surfactant than the cationic one. 3.5. Advanced Recovery of Oil by Using Microemulsion. Recovery assays were carried out to check the influence of the rock wettability inversion, from oil-wet to water-wet, on the efficiency of oil displacement in the rock pores. In each experiment, one microemulsion composition was selected for each surfactant, based on the best rock wettability inversion data that were previously determined. Water-rich microemulsions were also used because of their lower production costs. The composition selected for the application in oil recovery was 2% surfactant (CTAB, SDS, or UNT90), 4% cosurfactant (butan-1-ol), 92.8% 0.5 M NaCl aqueous solution, and 1.2% oil phase (kerosene). The fluid injection tests were performed in cores, and their properties are described in Table 7. Because the porosity and porous volumes of the cores were similar, it was expected that they would present similar behaviors during the conventional recovery step, which could Table 7. Cores Properties Used in the Oil Recovery
6757
cores
porosity (%)
porous vol. (cm3)
Soi
Swi
A B C
55.39 55.84 57.03
34.84 35.49 32.35
0.660 0.719 0.725
0.307 0.245 0.260
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be properly compared with their behaviors during the oil recovery with the microemulsions. Saturation of the cores with brine and oil were calculated after the first two injection steps. Six porous volumes of brine were injected through the rock, simulating water saturation. Also, six porous volumes of oil were injected to ensure initial oil saturation. Even in the brine injection stage, pressure monitoring was set to determine the permeability of the saturating fluid through the rock. The initial saturations of the cores are also presented in Table 7, where Soi is initial oil saturation and Swi initial water saturation. The recovery experiments were accompanied by plotting the percentage of oil recovered against the porous volume injected. For this stage, three porous volumes were injected, because over this value the amount of oil recovered was low, producing only water. The results of the recovery experiments for all three microemulsion systems are shown in Figure 8. Figure 8 shows that for all the cores tested, initially, when injecting brine (conventional method), the production of water did not occur up to 0.4 porous volumes. This fact is explained by the accommodation of the fluid injected into the pores; occupy the space of the displaced fluid. However, there was a moment when the production of water started up (approximately 3.0 porous volumes), known as “breakthrough.” From this moment on, a deficiency in the oil production occasioned by water occurred due to the difference in mobility between water and oil. This water exceeded the oil bank, and the swept away efficiency became inefficient in the reservoir, resulting in a residual oil saturation, at which point the conventional method could not produce it.22 It was also observed that the oil recovery by the conventional method did not exceed 66% for all three tests. In advanced recovery by using microemulsion, it is noticeable that the oil is recovered gradually since the beginning of the microemulsion injection, reaching a certain stabilization plateau after the injection of 2 porous volumes. Table 8 shows the oil recovery data based on the displacement efficiencies obtained. The oil recovery due to injection of microemulsion is based on the fact that the chemical methods involve the saturation of residual oil, and the microemulsions act in such a way as to homogenize the front of the injected fluid bank, minimizing interactions among fluids, fluids and the rock, and those associated with their viscosity, which is generally higher than the brine’s. The presence of relatively viscous fluids reduces mobility, preventing the formation of preferential paths.22 According to the results presented in Table 8, one can observe that all systems were efficient in recovering oil from the rock pores, since the total recovery efficiency was not lower than 88%. The CTAB microemulsion proved to be more efficient in recovering oil, with a total recovery factor as high as of 92.17%. For SDS and UNT90 systems, the total oil recovery efficiency was of 88.63% and 88.52%, respectively. There was a consistent correlation between the inversion of the rock wettability and the recovery efficiency because the order of rock wettability inversion was CTAB > SDS ≈ UNT90. This fact was already expected due to the ability of surfactants to inverse the rock wettability to neutral wettability, thus facilitating the oil displacement and improving the recovery rates.
Figure 8. Percentage of oil recovery when using microemulsion systems prepared with (a) CTAB, (b) SDS, and (c) UNT90.
4. CONCLUSIONS All microemulsions used were able to modify the wettability of the rock, from neutral to water-wet. The cationic surfactant molecules had a higher potential to increase the wettability of the limestone rock to water than anionic and nonionic surfactants. 6758
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Table 8. Recovery Data for the Cores: A (Microemulsion of CTAB), B (Microemulsion of SDS), and C (Microemulsion of UNT90) property
core A
core B
core C
K (mD) Soi Sor_conventional Sor_microemulsion EDC EDME EDT % OIPconventional % OIPmicroemulsion % OIPtotal
13.76 0.660 0.224 0.052 66.09% 76.91% 92.17% 66.09% 26.10% 92.17%
14.32 0.719 0.250 0.082 65.10% 67.42% 88.63% 65.10% 23.53% 88.63%
22.09 0.725 0.247 0.083 65.93% 66.30% 88.52% 65.93% 22.59% 88.52%
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Salinity also had a strong influence on the microemulsion structures with respect to the inversion effect in rock wettability. The inverse microemulsions presented a better inversion in the rock wettability (lower contact angle values), and the process of adsorption between the rock and the oil was more efficient. For the bicontinuous microemulsions, the increase in salinity decreased the contact angle of the brine with the rock, thereby improving the rock wettability with respect to water, in the case of surfactants SDS and UNT90, and increased wettability for the surfactant CTAB. All selected systems were efficient in advanced oil recovery, with a total recovery efficiency exceeding 88%. The microemulsion containing CTAB showed the highest efficiency of displacement when compared with the microemulsions with SDS and UNT90, which also had good efficiencies in advanced oil recovery. The effectiveness of surfactants in the modification of the rock wettability, from oil-wet to water-wet, influenced directly the recovery efficiency in the same order as the wettability: CTAB > SDS ≈ UNT90. This study showed the importance of rock−surfactant−oil interactions and their influence in improving oil recovery with the changing rock wettability.
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AUTHOR INFORMATION
Corresponding Author
*Phone: +55-84-32153773. Fax: +55-84-32153827. E-mail: tereza@eq ufrn.br. Notes
The authors declare no competing financial interest.
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ABBREVIATIONS Soi = initial oil saturation Swi = initial water saturation K = permeability Sor_conventional = residual oil saturation after injection of brine Sor_microemulsion = residual oil saturation after injection of microemulsion EDC = conventional displacement efficiency EDMA = advanced method displacement efficiency EDT = total displacement efficiency %OIP_conventional = recovery percentage of oil “in place” by the conventional method % OIP_microemulsion = recovery percentage of oil “in place” by the advanced method %OIPtotal = total recovery percentage of oil “in place” 6759
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