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Precise Wettability Characterization of Carbonate Rocks to Evaluate Oil Recovery using Surfactant-based Nanofluids Foad Haeri, and Dandina N. Rao Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b01827 • Publication Date (Web): 26 Aug 2019 Downloaded from pubs.acs.org on August 29, 2019
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Precise Wettability Characterization of Carbonate Rocks to Evaluate Oil Recovery Using Surfactant-based Nanofluids Foad Haeri* and Dandina N. Rao Craft and Hawkins Department of Petroleum Engineering, Louisiana State University, 3207 Patrick F. Taylor Hall, Baton Rouge, LA 70803
ABSTRACT Free energy of nanoparticles can increase the surface activity at the solid/oil/liquid contact line and remove oil through disjoining pressure gradient mechanism. Surfactants can also remove oil mainly by reducing interfacial tension, though raise economic concerns due to their adsorption on the rock surface. Introduction of nanoparticles to surfactant solutions seemed to be more prominent in improving the wettability than reducing the interfacial tension, which could offer an opportunity to develop costeffective chemical flooding agents to enhance oil recovery in carbonate reservoirs. However, characterization of wettability alteration using contact angles typically fails in providing consistent results. In this study, Dual-Drop Dual-Crystal (DDDC) technique was employed to measure precise and reproducible dynamic contact angles and supported by relative permeability curves generated by coreflood experiments to evaluate the wettability alteration performance of silica nanoparticles combined with both effective and ineffective anionic surfactants at both ambient and high-pressure high-temperature conditions. Adding nanoparticles to surfactants was seen to change the wettability of the carbonate rocks from strongly oil-wet to weakly oil-wet and intermediate-wet conditions (e.g. change in advancing contact angle of 167° to 98°), which improved the oil recovery (up to 93% of the original oil in place) and reduced the residual oil saturation, without having to significantly reduce the interfacial tension (only one or two orders of magnitude). Reduction of surfactant concentration in the combination did not significantly hinder the wettability alteration performance, showing the ability of nanoparticles to compensate for surfactants. Therefore, the combination of nanoparticles and low-cost dilute surfactants can be tuned to provide economically appealing chemical flooding agents to enhance oil recovery. 1. INTRODUCTION While the global demand for energy is expected to increase in the upcoming decades1 and the rate of discovering new fields has dropped in last few decades2, the importance of enhanced oil recovery (EOR) methods to reach about two thirds of the nation’s known resources that cannot be recovered by the conventional methods is undeniable.3 Despite the resulting high recovery, chemical flooding accounts only for 1.5% of the total number of active US EOR projects4,5, because of being too costly to be economical. This poses a great opportunity to develop new cost-effective chemical flooding technologies for improving oil recovery especially in carbonate reservoirs.
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Surfactants improve oil recovery by reducing the oil-water interfacial tension. However, a massive amount of surfactants is required to significantly reduce the residual oil saturation in the reservoir, due to their tendency to adsorb on the rock surface6. Though, by focusing on the wettability alteration capability of low-cost surfactants and adopting precise contact angle measurement techniques7,8, several attempts have been made to utilize surfactants and their combinations with other chemicals to enhance oil recovery. Application of nanotechnology in different industries9 particularly the upstream domain of the oil and gas industry10 has been the target of many researches in the last decade. The unique properties of nanoparticles that strongly depend on their size and shape11 create opportunities to influence the wetting behavior of the reservoirs. The wettability alteration has been reported to enhance oil recovery using different types of nanoparticles dispersed in various types of fluids11,12, such as silica nanoparticles functionalized with polyethylene glycol group in sodium chloride13, hydrophobic polysilicon nanoparticles in ethanol14, Gamma aluminum oxide nanoparticles in distilled water15, silane coated silica nanoparticles in potassium chloride16, and silica nanoparticles in distilled water in glass micromodel17. While some showed that silica nanoparticles in sodium chloride increased the interfacial tension (IFT) and changed the wettability of carbonate to strongly water-wet18, others significantly reduced the IFT using zinc oxide and silica nanocomposite coated with xanthan in low salinity water19, and some did not observe any effect on IFT using silica nanoparticles in water20. The employment of surfactants as dispersing fluid for nanoparticles has also been investigated to understand the mechanism of improving oil recovery21,22. While some reported an improvement in the oil production due to an increase in the adsorption of anionic surfactants in the presence of nanoparticles23, others recognized an increase in the free imbibition as the reason for enhancing oil recovery using nonionic surfactants and nanoparticles24. Change of wettability from oil-wet to water-wet has been observed in both sandstone25,26 and carbonate27 cores using anionic and cationic surfactants through coreflood and spontaneous imbibition experiments28. Recently, the advantage of nanoparticle-surfactants colloids over conventional surfactants by focusing on their rate of adsorption29 and ability to migrate deeper in the reservoir due to size exclusion and chromatographic effects30 has also been studied. Despite many attempts in evaluating the influence of nanoparticles along with surfactants on the wettability alteration behavior of reservoirs, a lack of confidence in adopting a precise technique to generate relatively consistent contact angles to determine the true wettability behavior of a system is observed. Additionally, most techniques seem to be incapable of properly catching the intermediate-wet zone that is the most favorable spot to significantly increase the capillary number (contact angle of 90º) and reduce the residual oil saturation. Moreover, utilizing a range of various combinations of nanoparticles and surfactant types for different rock types in the literature shows a lack of a complete understanding of wettability alteration mechanisms by surfactants in presence of nanoparticles and the contribution of IFT reduction in enhancing oil recovery. This 2 ACS Paragon Plus Environment
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work, by employing dual-drop-dual-crystal (DDDC) technique as a highly reproducible method to measure consistent dynamic advancing contact angles at both ambient and high-pressure-high-temperature conditions, provides a precise wettability characterization approach to evaluate oil recovery using surfactant-based nanofluids. This certainty about contact angle measurements supported by relative permeability curves, generated through the corefloods, provides an opportunity to better understand the mechanisms of enhancing oil recovery using surfactant-based nanofluids.
2.
EXPERIMENTAL SECTION A series of surfactants with a range of different structures, hydrophilicity levels, and chemical properties were screened in previous studies31,32 based on their ability to mobilize trapped oil through wettability alteration by measuring contact angles31 and conducting coreflood experiments32. In this study, the optimal concentration of nanoparticles to combine with the surfactant candidates was determined through contact angle and IFT measurements at ambient conditions. Then, the combination of optimal nanoparticles and selected surfactants (surfactant-based nanofluids) were tested for wettability alteration through contact angle measurements and coreflood experiments at different experimental conditions. 2.1. Materials Two groups of anionic surfactants, namely ALFOTERRA and SOLOTERRA designed for temperatures below and above 60 °C respectively, were provided by Sasol. Through screening in the previous studies31,32, ALFOTERRA S23-13S (ALF 13S) and SOLOTERRA 938 (SOL 938) were selected as the least effective surfactants at ambient and high-pressure high-temperature (HPHT) conditions respectively and ALFOTERRA S23-9S (ALF 9S) was selected as the most effective surfactant at ambient conditions. The candidates were then tested with the optimal concentration of nanoparticles to investigate their potential impact on wettability alteration performance. Figure 1 describes the typical structure of the surfactants.
Figure 1. Chemical structure of the surfactants tested for screening.31 The HPHT conditions were chosen based on Yates reservoir conditions (700 psi and 82 ˚F), whose dead crude oil was used in this study. However, the high temperature was set at 150 ˚F to provide a chance to use SOLOTERRA surfactants that are designed for temperatures above 60 °C. Indiana limestone outcrop cores to be used for both contact 3 ACS Paragon Plus Environment
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angle measurements and corefloods were purchased from Kocurek Industries. Sodium chloride (NaCl, 2 wt.%) was used as the reservoir brine. Table 1 lists the viscosity and density of Yates crude oil and brine at different temperatures tested in this study (72 ˚F and 150 ˚F). The viscosity of oil and brine were measured using Cannon-Fenske viscometer at both low and high temperatures. The concentration of surfactants to be used in this study for both contact angle measurements and corefloods were determined using a series of emulsion stability tests and supported by CMC analysis, whose details are provided by Gupta31 and Haeri32. Silica nanoparticles dispersed and stabilized in water, with the size of 30 nm and density of 1.029 g/cc, were purchased from US Research Nanomaterials, Inc. Since the experiments of this study were typically conducted over a short period of time, the stability conditions of the surfactant-based nanofluid solutions were checked and confirmed by a quick visualization right before conducting each experiment.
Table 1. Properties of Yates crude oil and brine at different temperatures.
2.2. Contact angle measurement setup and procedure The experimental setup for measuring the dynamic advancing contact angles is based on the DDDC technique. The measurements are made using Indiana limestone rock samples, Yates crude oil droplets, and different solutions including brine (2 wt.% NaCl), different surfactants, and nanofluids. The rock samples are cut to the size (0.4 in. × 0.5 in. × 0.2 in.), smoothened by three different polishing papers of variant grit sizes (120, 240, and 1200), cleaned in Soxhlet system using an organic solvent made by 83% methyl alcohol and 17% chloroform for 24 hours, boiled in deionized water for 2 hours, and finally oven-dried at 80 ºF for 24 hours. 2.2.1. IFT measurements Initially, the optical cell, as described in Figure 2, is filled with the solution (brine, surfactant, or nanofluid). Then, while oil is being injected from the needle as a pendant drop, images are captured by a high-quality digital camera and analyzed by the commercial Drop Shape Analysis software to estimate the IFT based on the initial input parameters.
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Figure 2. Schematic diagram (Left) and actual image33 (Right) of IFT and contact angle measurements setup, A: Optical cell, B: Digital camera, C: Oven. 2.2.2. Contact angle measurements To measure dynamic contact angles using DDDC technique, two oil droplets are placed beneath two polished rock samples through the needle. The samples and droplets are aged in the cell for 24 hours. Then, using the holders on top and side of the cell, the lower sample is flipped and the oil droplets on both samples are merged before aging for another 24 hours. At the stage of measuring the contact angles, the lower sample is gradually pulled in steps, as described in Figure 3, while the three-phase-contact-line (TPCL, the distance of the oil droplet to the edge of the rock sample), is monitored to record any movement of the oil droplet. After each step, the system is allowed to equilibrate for 30 minutes before capturing the image for contact angle analysis using the Drop Shape Analysis software. Once normalized TPCL changed (i.e. the solution advanced over the area previously occupied by the oil), the angle made by the droplet at the point of movement on the lower crystal in the solution phase (as shown in Figure 3) is identified as the dynamic advancing contact angle.
Figure 3. Monitoring the droplet movement to determine the dynamic advancing contact angle using DDDC technique.
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The procedure of measuring contact angles is similar at both ambient and HPHT conditions. Although the contact angle measurements of this study were performed at ambient conditions and 700 psi and 150 °F as the HPHT conditions, the cell is designed to measure contact angles at pressures and temperatures up to 20,000 psi and 400 °F respectively. The categorization of contact angles and their respective wettability alteration behavior are relatively defined for this study as listed in Table 2. Table 2. Wettability alteration behavior and contact angle ranges defined for this study
2.3. Coreflood experiments setup and procedure The experimental setup for the corefloods, as described in Figure 4, consisted of a core holder (Phoenix Instruments) designed for maintaining cores with length of 12 in. and diameter of 2 in. at high pressures (maximum 5,000 psi) and high temperatures (maximum 210 °F), a back pressure regulator (Equilibar, maximum 5,000 psi) to establish reservoir pressure, heating tape and insulating blanket to provide high temperatures, thermometer (Hanna Instruments) to determine the approximate temperature of the core, a manual hydraulic oil pump (Enerpac) to manage the confining pressure, transfer vessel (CoreLab, 500 cc) to store and displace fluids, two pressure transducers (Omega, maximum 2500 psi) to record the inlet/outlet pressures by communicating through the data acquisition system (Omegabus) to monitor the live variation of differential pressure across the core, and a constant-rate pump (LabAlliance, Series 1500).
Figure 4. Schematic diagram (Left) and actual image (Right) of coreflood experimental setup, A: Core holder, B: Confining pressure gauge, C: Pressure transducer, D: Back-pressure regulator, E: Effluent burette, F: By-pass line, G: Transfer vessel, H: Constant-rate pump, I: Pump reservoir, J: Confining pressure pump. 6 ACS Paragon Plus Environment
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The core holder and tubing lines are cleaned using toluene, acetone and deionized water to remove any contamination. A fresh core is cleaned with air and covered with heat shrink Teflon wrap before being placed inside the core holder. After vacuuming, the pore volume of the core is measured using the crude oil. Then, the absolute permeability of the core is determined by injecting crude oil at different rates and recording the pressure drop. The initial condition of the core is established by injecting brine followed by crude oil to arrive at initial water saturation. Then, the core is aged for a period of 8 days, which was experimentally determined32 for the system used in this study. Finally, the injecting fluid (brine for waterflood and surfactant or nanofluid for chemical flood) was introduced at 2 cc/min, as secondary recovery method. The reason that chemicals were not injected as tertiary recovery method (after a waterflood, as typically expected) was to have a sufficient amount of oil-in-place in the core (with similar characterisitics) for comparison of recovery using different formulations. The effective permeabilities for each specific flood is estimated by injecting the fluid at different rates and recording the pressure drop data. All the produced fluids are collected to determine the recovery and residual oil saturation. The absolute and effective permeabilities and water and oil saturation values are used to determine the experimental relative permeability end points, which are implemented into the simulator (CMG STAR) along with the oil recovery and pressure drop variations to perform the history-matching and optimization using CMOST. 3. RESULTS AND DISCUSSION 3.1. Initial wettability condition The initial wettability condition of the system was determined through DDDC technique by measuring advancing contact angle of Yates crude oil droplet on a limestone rock sample immersed in brine without surfactant or nanoparticles. Figure 5 shows the actual images of the droplet at each step, starting with the static contact angle of 145° (before moving the lower sample to the left) and ending with the dynamic advancing contact angle of 167° (before the droplet moves on the lower sample), which represents the strongly oil-wet behavior of the system. The variation of contact angles and TPCL movement with time are described in Figure 6. The highest angle was determined to be 167° as the true dynamic water advancing contact angle, where the normalized TPCL curve drops. To ensure the accuracy and reproducibility of the measurements, each experiment was repeated twice by moving the rock back to its original position, mingling the droplets, and shifting the lower sample in steps.
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Figure 5. Determination of initial wettability condition through DDDC method using Yates oil droplet between limestone rock samples immersed in brine at ambient conditions.
Figure 6. Contact angles variation and droplet movement record in DDDC method using Yates oil droplet between limestone rock samples immersed in brine at ambient conditions.
3.2. Optimal nanoparticles concentration The optimal concentration of nanoparticles for wettability alteration was determined by preparing solutions of nanoparticles in brine (brine-based nanofluids) and measuring IFT and contact angles at ambient conditions. The concentration of brine-based nanofluids ranged from 0 wt.% (initial wettability condition of the system) to 0.8 wt.%. After each experiment, the optical cell was emptied and cleaned. Fresh rock samples were mounted and then the cell was filled with the new fluid containing higher concentration of nanoparticles. Figure 7 describes dynamic advancing contact angles and IFT values along with the actual images of the droplets from DDDC experiment for different concentrations of nanoparticles in brine at ambient conditions.
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Figure 7. Contact angles and IFT values for different concentrations of nanoparticles in brine (2 wt.% NaCl) at ambient conditions. Increasing the concentration of nanoparticles (from 0 wt.% to 0.8 wt.%) seemed to generate lower advancing contact angles without significantly lowering the interfacial tension. At initial condition, in which brine contains no nanoparticles, the contact angle is 167° representing a strongly oil-wet condition. The IFT value is immediately reduced from 23.2 mN/m (at initial condition) to 13.1 mN/m, when 0.1 wt.% nanoparticles is added to the brine, but the contact angle stays in the strongly oil-wet zone (165°). By adding more nanoparticles, the reduction of IFT and contact angles continues to reach 9.8 mN/m at 156° and 7.2 mN/m at 146° for the concentrations of 0.2 wt.% and 0.4 wt.% respectively. This reduction slows down toward the higher concentration of nanoparticles to result in an IFT value of 6.5 mN/m and contact angle of 143° at 0.8 wt.%. Since doubling the concentration of nanoparticles from 0.4 wt.% to 0.8 wt.% did not significantly contribute in lowering the IFT as well as the advancing contact angle, 0.4 wt.% seemed to be the optimum concentration of nanoparticles in terms of wettability alteration for the system of this study. By adding 0.4 wt.% nanoparticles to brine, the wettability of the limestone/Yates-oil/NaCl system was changed from strongly oil-wet to weakly oil-wet at ambient conditions. The structural disjoining pressure gradient promoted by the Brownian motion and electrostatic repulsion between the particles and the specific spreading behavior of nanoparticles in the confined wedge area at the three-phase contact line of solid/oil/nanofluid have been suggested by researchers as the main mechanism for enhancing oil recovery.34,35,36,37 However, the attempts might not be sufficient to explain the mechanisms in such strongly oil-wet systems as of this study (167° at initial condition), where the wedge area is absent due to the existence of large contact angle. Based on the observations of this study, it is believed that the nanoparticles attached at the interface of oil/nanofluid could (by reducing the IFT) potentially dislodge some of the oil from the solid surface at the three-phase contact line and change the shape of the oil drop, which could also explain the reduction in the contact angles observed after increasing the concentration of nanoparticles (from 167° at 0 wt.% to 143° at 0.8 wt.%). 9 ACS Paragon Plus Environment
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Therefore, a space is provided for nanoparticles to structure themselves at the three-phase contact line of solid/oil/nanofluid. Additionally, the limestone rock samples are mainly composed of calcite, whose surface roughness was characterized by Vijapurapu & Rao38 to be between 1.17 μm for a smooth and 5.46 μm for a roughened surface. Therefore, there could also be a possibility for nanoparticles of this study (silica, 30 nm), by being three orders of magnitudes smaller than the average surface roughness of the rock samples, to seep into the solid surface asperities caused by the surface roughness, at the three-phase contact line and thereby dislodge the oil from the surface even at extremely high contact angles caused by strongly oil-wet conditions. 3.3. Contact angle measurements 3.3.1. Nanoparticles and an ineffective surfactant at ambient conditions To study the potential impact of nanoparticles on the wettability alteration performance of surfactants at ambient conditions, ALF 13S (100 ppm) was used to prepare the surfactant-based nanofluids (NF) for the contact angle measurements. Figure 8 depicts the dynamic advancing contact angles, IFT values, and the actual images of the droplets from DDDC technique for the surfactant-based nanofluids made by adding optimal concentration of nanoparticles (0.4 wt.%) to the least effective surfactant at ambient conditions, screened previously31,32.
Figure 8. Contact angles and IFT values for surfactant-based nanofluids made by the least effective surfactant (ALF 13S-100 ppm) at ambient conditions. The IFT was significantly lowered by the surfactant from 23.2 mN/m to 0.02 mN/m. However, the contact angle stayed in the strongly oil-wet zone (162°), which confirmed the inability of this surfactant to change the wettability of the system. The mixture of nanoparticles in brine (0.4 wt.%) had resulted in a contact angle of 146°, which is lower than that of surfactant alone. However, adding 0.4 wt.% nanoparticles to surfactant seemed to generate the lowest contact angle of 116° with IFT value of 1.2 mN/m. This showed the incredible potential of nanoparticles to boost the performance of 10 ACS Paragon Plus Environment
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surfactant in shifting the wettability of the system into intermediate-wet zone without having to significantly reduce the IFT. Moreover, when the concentration of the surfactant was lowered from 100 ppm to 50 ppm, the contact angle stayed fairly close to the intermediate-wet zone (121°). This showed that a nearly consistent wettability alteration and IFT reduction behavior can be achieved even after lowering the concentration of surfactant. 3.3.2. Nanoparticles and an effective surfactant at ambient conditions The dynamic advancing contact angle, IFT values, and the actual images of the droplets from DDDC technique for the surfactant-based nanofluids made by the most effective surfactant (ALF 9S, 100 ppm) at ambient conditions are shown in Figure 9. The surfactant was strong enough to lower the contact angle from 167° (at initial condition) to 117°, changing from strongly oil-wet to intermediate-wet zone. The enhancement continued even further after combining surfactant with nanoparticles to generate a contact angle of 98° and IFT value of 0.85 mN/m, a great representation of intermediate-wet behavior. The IFT increased slightly to 1.6 mN/m and the contact angle did not change drastically to still stay in the intermediate-wet zone, when the concentration of surfactant was lowered to 50 ppm. Therefore, a similar wettability behavior was observed even after lowering the concentration of surfactant in the combination.
Figure 9. Contact angles and IFT values for surfactant-based nanofluids made by the most effective surfactant (ALF 9S-100 ppm) at ambient conditions. 3.3.3. Nanoparticles and an ineffective surfactant at HPHT conditions At HPHT conditions, SOL 938 (100 ppm) was used and generated an IFT value of 0.02 mN/m and a contact angle of 150° representing an oil-wet behavior similar to brine (156°) at initial condition (Figure 10). While 0.4 wt.% nanoparticles in brine (with no surfactant) resulted in a lower contact angle (135°) compared the surfactant solution, adding nanoparticles to surfactant seemed to generate the lowest contact angle of 108° with IFT value of 1.5 mN/m. When the concentration of surfactant was lowered from 100 ppm to 50 ppm, the contact angle slightly increased to 114° but still stayed in the intermediate-wet zone, while the IFT remained within the same order of magnitude (1.5 mN/m). 11 ACS Paragon Plus Environment
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Figure 10. Contact angles and IFT values surfactant-based nanofluids made by the least effective surfactant (SOL 938, 100 ppm) at HPHT conditions (700 psi and 150 °F). The process of dislodging the oil by nanoparticles seemed to be stimulated when surfactants were present, as it became easier to lift the oil drop from the surface. The contact angle reduced from 146° to 116° at ambient conditions and from 135° to 108° at HPHT conditions. This impact was even more prominent when an effective surfactant was used (from 146° to 98°), representing a wettability alteration to intermediate-wet zone. On the other hand, the combination of nanoparticles and surfactants (in all cases) did not considerably lower the interfacial tension (as opposed to just surfactant), while it shifted the wettability to intermediate-wet by lowering the contact angles. Moreover, the wettability alteration behavior was similar even after lowering the concentration of surfactant in the combined solutions. Therefore, nanoparticles seemed to be able to compensate for the surfactants in changing the wettability from strongly oil-wet to intermediate-wet. It appears that the rock-fluid interactions of surfactant-based nanofluids are more dominated by energetic nanoparticles, while only a slight reduction in interfacial tension is required by the diluted surfactant for wettability alteration This may potentially suggest a lesser necessity of surfactant adsorption on the rock to change the wettability and consequently alleviate the financial concerns on using chemical flooding to enhance oil recovery.
3.4. Coreflood experiments To explore the wettability alteration influence of nanoparticles and their combination with surfactant on overall recovery and relative permeability curves, coreflood experiments were conducted at different experimental conditions. The corefloods at each condition included waterflood (2 wt.% NaCl), brine-based nanofluid flood (0.4 wt.% nanoparticles in brine with no surfactant), surfactant flood (2000 ppm surfactant in brine with no nanoparticles), and surfactant-based nanofluid flood (0.4 wt.% nanoparticles added to 2000 and 1000 ppm surfactants). Using the history-match of the experimental data (oil recovery and pressure drop), relative permeability curves were generated, which 12 ACS Paragon Plus Environment
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provided insight about the potentials of each solution in changing the wettability of the system. A history-match representing the waterflooding performed on a limestone core (with permeability of 23.6 mD and porosity of about 18%, saturated with Yates crude oil) using brine (2 wt.% NaCl) at 500 psi and 72 ˚F is described here (Figure 11a) along with the resulted experimental relative permeability endpoints and simulated curves (Figure 11b). The ultimate oil recovery of about 20% and the position of relative permeability curves (crossover point below water saturation of 0.5 and water endpoints higher than oil endpoints) clearly indicates the strongly oil-wet behavior of the core, which is supported by contact angle measurements (167°). The history-match of oil recovery and pressure drop along with the relative permeability curves and other information about the rest of the corefloods of this study are provided in the Supporting Information section.
Figure 11. (a) History match of oil recovery and pressure drop and (b) relative permeability curves for waterflood (2 wt.% NaCl) at 500 psi and 72 ˚F. 3.4.1. Nanoparticles and an ineffective surfactant at ambient conditions The coreflood oil recovery results for different solutions prepared with the least effective surfactant at 500 psi and 72 ºF are shown in Figure 12. Other than the waterflood, which recovered only about 20% of the original oil in place, the injection of ALF 13S at 2000 ppm was also not able to improve the recovery (21%) and left the system in the strongly oil-wet state. On the other hand, optimal brine-based nanofluid (0.4 wt.% nanoparticles in brine) led to an oil recovery of about 31%. After adding nanoparticles to the surfactant, the recovery boosted up to more than 57%. The participation of nanoparticles in the recovery was so effective that the recovery stayed around 53%, even after reducing the concentration of surfactant to 1000 pm in the surfactant-based nanofluid solution. Figure 13 shows the relative permeability ratio curves (Krw/Kro) generated from the history match results. The surfactant flood shows no shift-to-right compared to the waterflood as the surfactant was not effective to change the wettability of the system toward less oilwet, which is also in agreement with the contact angle measurements (162°). However, the combination of the same surfactant with nanoparticles resulted in a great shift-to-right and a significant reduction in the residual oil saturation, even better than the optimal brine-based nanofluid (nanoparticles in brine with no surfactant), making the system less oil-wet as it was also observed in the contact angle measurements (116°). The behavior was similar even after reducing the concentration of surfactant in the combination to 1000 ppm, as it showed a great shift-to-right compared to using only surfactant (with no nanoparticles). 13 ACS Paragon Plus Environment
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Figure 12. Experimental coreflood oil recovery using nanofluids made by the least effective surfactant (ALF 13S) at 500 psi and 72 ˚F.
Figure 13. Relative permeability ratio curves for nanofluids made by the least effective surfactant (ALF 13S) at 500 psi and 72 ˚F.
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3.4.2. Nanoparticles and an effective surfactant at ambient conditions The positive impact of nanoparticles on enhancing oil recovery was even more pronounced using the most effective surfactant at 500 psi and 72 ºF as described in Figure 14. The injection of ALF 9S at 2000 ppm resulted in a recovery of about 48%, which was raised even higher after adding nanoparticles to reach about 93%. The contribution of nanoparticles in the recovery was so effective that the recovery stayed around 86%, even after reducing the concentration of surfactant to 1000 ppm in the surfactant-based nanofluid solution. The relative permeability ratio curves (Figure 15) also revealed a great shift-to-right using the most effective surfactant (even greater than that of the brinebased nanofluid with no surfactant) compared to the waterflood. The shift was more enhanced after combining with nanoparticles leading to a residual oil saturation of less than 0.1 representing a system that was no longer oil-wet, which also agreed well with contact angle measurements (98°). The reduction of surfactant concentration resulted in a slight shift back to the left, but still showed a great potential of nanoparticles to boost the performance of an effective surfactant to enhance oil recovery.
Figure 14. Experimental coreflood oil recovery using nanofluids made by the most effective surfactant (ALF 9S) at 500 psi and 72 ˚F.
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Figure 15. Relative permeability ratio curves for nanofluids made by the most effective surfactant (ALF 9S) at 500 psi and 72 ˚F. 3.4.3. Nanoparticles and an ineffective surfactant at HPHT conditions At HPHT conditions (700 psi and 150 ºF), as seen in Figure 16, the waterflood helped to produce only about 17.5% of the original oil in place and SOL 938 at 2000 ppm, as the least effective surfactant at HPHT conditions, was not able to significantly improve the recovery (22%). While brine-based nanofluid (0.4 wt.% nanoparticles in brine with no surfactant) led to an oil recovery of about 29%, the surfactant-based nanofluid improved the recovery to about 52%. The recovery stayed around 45% even after reducing the concentration of surfactant to 1000 pm in the surfactant-based nanofluid solution. The relative permeability ratio curves (Figure 17) generated by the surfactant flood also showed a strongly oil-wet behavior in agreement with contact angle measurements (150°). The addition of nanoparticles shifted the curves to right showing a wettability alteration toward less oil-wet zone and the behavior was repeated even after lowering the surfactant concentration to 1000 ppm.
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Figure 16. Experimental coreflood oil recovery using nanofluids made by the least effective surfactant (SOL 938) at 700 psi and 150 ˚F.
Figure 17. Relative permeability ratio curves for nanofluids made by the least effective surfactant (SOL 938) at 700 psi and 150 ˚F. 17 ACS Paragon Plus Environment
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Therefore, nanoparticles not only enhanced the oil recovery for this system through wettability alteration toward less oil-wet condition, but they could also improve the performance of an ineffective surfactant at both experimental conditions. The impact was even more pronounced when nanoparticles were combined with an effective surfactant, which could provide an opportunity to develop a financially appealing chemical flooding agent using low-cost dilute effective surfactants in combination with nanoparticles.
4.
CONCLUSIONS
This study helped to better understand the mechanism of enhancing oil recovery in carbonate rocks using surfactant-based nanofluids through wettability alteration. Wettability was precisely quantified through the highly reproducible DDDC technique and supported by relative permeability curves generated through corefloods. The summary of all the coreflood results at different experimental conditions and their respective contact angle and IFT measurements along with their wettability alteration behavior are described in Figure 18 and listed in Table 4.
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Figure 18. Summary of the coreflood results and contact angle measurements of all the solutions at different experimental conditions.
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Table 4. Summary of the coreflood results and contact angle measurements of all the solutions at different experimental conditions.
The following summarizes the most significant findings of this work:
The optimum concentration of silica nanoparticles in brine (0.4 wt.%) lowered the contact angle from 167° to 146° and the interfacial tension from 23.2 mN/m to 7.2 mN/m, changing the wettability of the limestone rock from strongly oil-wet to oilwet, which resulted in a 10% increase in the oil recovery at both ambient and HPHT conditions. The performance of the ineffective surfactant was improved by adding optimal nanoparticles, which resulted in a wettability alteration to intermediate-wet (contact angles of 116° and 108° at ambient and HPHT conditions respectively) and incremental oil recovery of 37% and 30% (compared to the surfactant flood) at ambient and HPHT conditions respectively. Even after 50% reduction in the surfactant concentration, the system still showed intermediate-wet behavior (121° and 114° at ambient and HPHT conditions respectively) leading to high ultimate oil recoveries (about 53% and 45% at ambient and HPHT conditions respectively). This trend was also observed with the effective surfactant to reach even lower contact angles (98° and 109°) and higher oil recoveries (93% and 86%), before and after reduction in the surfactant concentration. The potential mechanisms for enhancing oil recovery using surfactant-based nanofluids through wettability alteration in such strongly oil-wet systems as of this study, where the wedge area of the solid/oil/nanofluid contact point is absent 20 ACS Paragon Plus Environment
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due to the existence of large contact angles, may be explained by the attachment of nanoparticles at the interface of oil/nanofluid to partially dislodge the oil and the possibility of nanoparticles seeping into the asperities of the rock surface at the contact point that could potentially help with creating the area for nanoparticles to structure themselves at the contact point of solid/oil/nanofluid. The carbonate rocks were used in this study to create an oil-wet environment to test surfactant-based nanoparticles. Replicating the situation of a reservoir in the lab, particularly carbonate reservoirs, requires tougher conditions, such as higher pressures, temperatures, and salinities, which might make the results less favorable in terms of enhancing oil recovery through wettability alteration. Future work will look into the impact of a wider variety of pressures, temperatures, and salinities on contact angles, IFT, and oil recovery. The combination of dilute surfactants with nanoparticles seemed to be able to lower the residual oil saturation through wettability alteration toward intermediate-wet condition without having to significantly reduce the IFT, which would potentially make the surfactant-based nanofluid an economically appealing chemical agent to improve oil recovery in carbonate reservoirs. A comprehensive economic justification considering factors such as material lost, water disposal, operational costs, etc. will be delivered in the future work.
ASSOCIATED CONTENT Supporting Information Details of all the coreflood experiments of this study, including the core parameters, experimental conditions, oil recovery and pressure drop history-match, and relative permeability curves. This material is available free of charge at http://pubs.acs.org. AUTHOR INFORMATION Corresponding Author *Email:
[email protected] Tel.: +12254001988
Notes The authors declare no competing financial interest. There is no funding source or grant/award numbers to report.
ABBREVIATIONS ALF, ALFOTERRA; DDDC, dual drop dual crystal; EOR, enhanced oil recovery; HPHT, high pressure high temperature; IFT, interfacial tension; NF, nanofluids; SOL, SOLOTERRA; TPCL, three-phase contact line.
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ACKNOWLEDGEMENT The research reported in this work was carried out as part of a graduate study at the Craft & Hawkins Department of Petroleum Engineering at Louisiana State University (LSU). The authors would like to thank the EOR team in Sasol for providing insight and support on surfactants particularly throughout the initial stages of this study and CMG Ltd. for the simulation software license. We express our appreciation to Nicholas Dinecola from LSU Advance Manufacturing and Machining Facility and Joe M. Bell and Nick S. Lombardo from LSU ChemE Shop for their supportive cooperation during this work.
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