Nanoscale Investigation of Surfactant-Enhanced Solubilization of

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Nanoscale Investigation of Surfactant-enhanced Solubilization of Asphaltenes from Silicate-rich Rocks Tianzhu Qin, Gina Javanbakht, and Lamia Goual Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b03228 • Publication Date (Web): 16 Nov 2018 Downloaded from http://pubs.acs.org on November 17, 2018

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Nanoscale Investigation of Surfactant-enhanced Solubilization of Asphaltenes from Silicate-rich Rocks Tianzhu Qin, Gina Javanbakht, Lamia Goual* Department of Petroleum Engineering, University of Wyoming, Laramie, WY 82071, USA * Email: [email protected], phone: 307-766-3278

ABSTRACT The main goal of this study was to investigate the impact of two non-ionic surfactants on the solubilization of dense non-aqueous phase liquids (DNAPL) found in crude oils, namely asphaltenes, from silicate-rich rocks with different mineralogy, pore topology and wettability states (Bentheimer and Arkose). The surfactants consisted of n-dodecyl β-D-maltoside and triton X-100, which displayed similar properties with the exception of their hydrogen-bonding ability. High-resolution microscope imaging, wettability measurements, and spontaneous imbibition tests were conducted to study the performance of these surfactants on DNAPL solubilization. The interactions between asphaltene molecules, surfactants, and a mineral surface with H-bonding ability were further examined at the molecular-level using molecular dynamics simulations. The results revealed that maltoside could restore the wettability of both sandstones to a higher extent than triton because of its high H-bonding ability with the silanol groups of quartz. This behavior was even more pronounced in tight rocks, such as Arkose, resulting in incremental light nonaqueous phase liquids (LNAPL) mobilization from small pores. Early stages of micellar solubilization of DNAPL by maltoside were successfully observed through molecular dynamics simulations. The solubilization was promoted by surfactant self-assembly, leading to the formation of a continuous surfactant channel that interacted with asphaltenes and promoted their desorption from the mineral surface. This phase eventually grew into a thick surfactant shell trapping DNAPL in its core, as suggested by high-resolution transmission electron microscope (HRTEM) micrographs of microemulsions formed by these NAPL/surfactant-in-brine systems. KEYWORDS: Asphaltene, NAPL, surfactant, solubilization, wettability, EOR, aquifer remediation.

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1.

INTRODUCTION

Understanding three-phase flow processes in porous media is key to enhancing oil recovery from subsurface formations or remediating oil-contaminated aquifers. Although the majority of crude oils are classified as light non-aqueous phase liquids (LNAPLs), they often contain large polarizable and polydisperse surfaceactive molecules, called asphaltenes, that are denser than water. The adsorption of these dense non-aqueous phase liquids (DNAPLs) on rock surfaces can alter their wettability, impacting the displacement mechanisms in porous media.1 Molecular forces such as van der Waals, π-π stacking, and acid-base interactions were found to affect the adsorption process.2 Asphaltenes with high heteroatom content, aromaticity, and polarity showed greater adsorption propensity on surfaces.3–5 In particular, the presence of polar functional groups in asphaltenes, such as hydroxyl, carboxyl, and sulfino groups, promoted their interactions with solid surfaces.6,7 The molecular size of asphaltenes also has a direct impact on their adsorption. Larger asphaltene molecules tend to adsorb more on silica compared to smaller resin molecules.8 The adsorption process is dominated by kinetics rather than equilibrium in the presence of flow,9 and can be either in monolayer or multilayer based on asphaltene molecular structure and experimental conditions.10 The wettability alteration caused by asphaltene adsorption on mineral surfaces often results in negative threshold capillary pressures that can leave a large portion of residual NAPL in subsurface formations. The amount of oil trapped inside the pores can be reduced by introducing low concentrations of surface-active chemicals such as surfactants in the injection of water. Surfactants are amphiphilic molecules that consist of a hydrophilic head and a hydrophobic tail.11 They tend to adsorb at liquid/liquid and liquid/solid interfaces and affect their physical properties. For instance, their ability to reduce the interfacial tension (IFT) between NAPL and brine enables them to enhance the mobilization of small and deformable oil droplets through porous media.12 Through micellar solubilization, they can also promote the wettability restoration of mineral surfaces from oil-wet state back to their original water-wet state.13,14 The propensity of surfactants to solubilize asphaltenes depends on their physicochemical properties.15–17 Surfactants with rich hydrophilic groups, such as sugar-based alkyl glucosides and alcohol ethoxylates with various ethylene oxide numbers (EON), tend to interact with mineral surfaces due to their strongly surfaceactive hydrogen-bonding groups.18–20 This property enables them to adsorb in bilayers on rock surfaces, promote micellar solubilization, and reverse wettability.21 Cationic surfactants, including tetra alkyl ammonium, are found to desorb DNAPLs by forming ion-pairs with negatively charged organic

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carboxylates and consequently solubilize absorbed organic layers.22 Anionic surfactants, on the other hand, can form a water-wet surfactant monolayer on the oil-wet rock surfaces via hydrophobic interactions with DNAPL adsorbed on mineral surfaces, thereby restoring wettability and reversing the capillary pressure from negative to positive.23 Even though the impact of surfactants on NAPL mobilization through IFT reduction has been extensively investigated in the past, studies on their molecular interactions with mineral surfaces leading to DNAPL (or asphaltene) solubilization are very limited.24,25 In particular, the ability of different surfactant structures to alter wettability is still unclear. Existing molecular dynamics (MD) simulations of these systems mainly considered single asphaltene structures in a solvent to represent model oils, while important factors such as molecular polydispersity were disregarded.24 Solubilization mechanisms, such as shrinking of solid-oilwater contact line due to brine penetration between solid and oil phase,11 diffusion and swelling of water at the solid interface,12,13 and surfactant adsorption on mineral surfaces were not considered.26–28 The objective of this work was to investigate the impact of surfactant structures on asphaltene solubilization mechanisms and their implications on fluid flow in porous media. The performance of two nonionic surfactants (Triton X-100 and n-dodecyl β-D-maltoside) was demonstrated experimentally by using two rocks with H-bonding ability but different pore topology and wettability states. To understand the molecular interactions involved in these systems, large-scale MD simulations were performed using a polydisperse asphaltene model in toluene,29 a H-bonding mineral surface, and the two nonionic surfactants used in the experiments. Novel insights were gained regarding the impact of surfactant structures on wettability restoration of mineral surfaces.

2. 2.1

MATERIALS AND METHODS Rocks

Two different sandstones were selected for this study: (i) Bentheimer outcrop from Germany, and (ii) Arkose aquifer rock from Owl Canyon in northeast Colorado. Both rocks were cut into cores 1 inch in diameter and 2 inches in length. The cores were baked at 110C for 24 hours to remove moisture. The porosity and permeability of the dry cores were measured using an automated permeameter and porosimeter (AP-608, Coretest system), and are provided in Table 1. The tomographic images of the rocks and corresponding pore size distribution curves are displayed in Figure 1. They were evaluated using an FEI Heliscan micro-CT scanner with a resolution of 1.5 µm per voxel at 60 µA and 100 kV. The tomographic images were captured and reconstructed by Qmango (software) and then analyzed by Avizo (software). Bentheimer has a unimodal pore size distribution with an average pore size of about 105 m. In contrast,

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the pore size distribution of Arkose exhibits two peaks at about 27 m (throats) and 88 m (pores). Figure 1 and Table 2 show the composition and mineral map of the rocks, captured by an FEI QEMSCAN 650F at 25 kV, 6.2 nA, and a resolution of 0.73 µm per pixel. Bentheimer consists mostly of quartz (97 %) whereas Arkose has a more heterogeneous mineral composition with over 66% of silicates (quartz and feldspar), 28% of carbonates (calcite and dolomite), and 6% clays. 2.2

NAPL

A medium crude oil from the Milne Point Formation in Alaska was selected as the NAPL phase. It was centrifuged at 6000 rpm for one hour and then filtered with 0.5 μm filter paper. This oil contains 9 wt% of C7 asphaltenes measured according to ASTM D-2007. The total acid number (TAN) and total base number (TBN) of the oil were measured using a Metrohm 808 titrando titrator. The physicochemical properties of this NAPL are presented in Table 3. 2.3

Brine solutions

The brine was composed of 1 M CaCl2 in distilled-deionized water. The ions and salinity were determined according to a previous study.30 Triton X-100 (laboratory grade, Sigma-Aldrich) and n-dodecyl β-Dmaltoside (> 98%, Sigma-Aldrich) were selected as nonionic surfactants with similar molecular weight and Hydrophile-Lipophile Balance (HLB) numbers, which were calculated using Griffin's method31: HLB = 20 × 𝑀ℎ/𝑀 where Mh is the molecular mass of the hydrophilic portion of the molecule, and M is the molecular mass of the whole molecule. These surfactants are environmentally friendly due to their low toxicity and good biodegradability. The properties and structure of the two surfactants are reported in Table 4. They were separately added to brine to prepare two surfactant solutions (triton and maltoside) at 0.33 wt% surfactant concentration. Upon addition to brine, the IFT reduced from 22.7 mN/m to 0.97 mN/m and 0.67 mN/m with maltoside and triton, respectively. Therefore, the IFT generated by both surfactant solutions was comparable and within the same range. 2.4

Contact angle

The average static contact angle (CA) of brine/NAPL/rock systems was measured using a custom-built apparatus with a standard deviation less than 5.32 Bentheimer and Arkose rock substrates were vacuumed at 10-7 psi for 24 hours then saturated and aged in NAPL at 60 C for 7 days. The aged substrates were carefully placed in the CA cell then immersed in different brine solutions. The solutions could spontaneously imbibe into the substrates, displace NAPL out of the rocks, and form NAPL droplets on the rock surfaces. Images of these NAPL droplets were captured during the first 36 hours and analyzed by

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ImageJ (software) to determine the average static contact angles, which were measured from the solid surface through the water phase. 2.5

Spontaneous imbibition

Spontaneous imbibition tests were conducted with Bentheimer and Arkose cores to estimate the surfactant effectiveness in displacing oil. The cores were vacuumed, NAPL-saturated, and aged according to the method described in Section 2.4. They were then placed in Amott cells and immersed separately in different brine solutions. The amount of NAPL recovered from each core was recorded over time until the production process was complete. 2.6

High Resolution Transmission Electron Microscopy

Tecnai TF20 S-Twin High-Resolution Transmission Electron Microscope (HRTEM) from FEI was used to image microemulsions formed by crude oil and surfactant solutions. The microscope features a TIETZ F415MP 4k  4k multiport CCD camera with a 4-port readout and 15 μm pixel size. Oil-in-water microemulsions were prepared by extracting a small amount of the rag layer between NAPL and brine and then diluted 40 times. The prepared samples were placed on silicon dioxide custom coated carbon TEM grids from SPI Supplies. They were imaged by the microscope at 200 kV accelerating voltage under bright field illumination mode. Image J was used to process the images and measure the droplet size of microemulsions.30,33 2.7

Molecular dynamics simulations

Two sets of MD simulations were conducted to study asphaltene/mineral interactions and the impact of surfactant structures on asphaltene desorption. In the first set of simulations, nine different asphaltene molecules were selected to represent a polydisperse DNAPL model, as shown in Table 5. More details on the aggregation behavior of this polydisperse mixture in bulk phase can be found in our previous study. 29 The model molecules were placed on mineral surfaces separately then covered by the brine solutions used in the experimental study (i.e., 1M CaCl2, triton, and maltoside). To represent a smooth mineral surface with H-bonding ability, we used a rigid calcite model with restrained carbon atoms and calcium cations. For this surface, we followed the force field used by Sedghi et al., which combines Raiteri’s model with CHARMM36 LJ parameters.34,35 This model was more representative of sandstones than carbonates because it is smooth, non-reactive in brine, and has high H-bonding ability. Note that we did not use a quartz surface because of the uncertainties in the degree of potentization of quartz that can affect the adsorption process.

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The brine/NAPL/mineral systems were equilibrated for 10 ns at 300 K and 1bar. As a reference, separate simulations with surfactant solutions were run on the mineral surface until they reached equilibrium during 40 ns at 300 K. In the second group of simulations, 105 molecules of the polydisperse DNAPL model were solvated in toluene. The final concentration of toluene was 50 wt%. The solution was placed on the mineral surface with an area of 9.716 × 9.98 nm2 and a thickness of 3.643 nm, which was then extended to an area of 9.716 × 13.972 nm2. We annealed the toluene molecules by increasing their temperature from 300 to 400 K followed by a slow cooling back to 300 K during a total of 20 ns simulation time. Then the simulation was run for another 100 ns to equilibrate the system. Similar to the first group, simulations with brine and surfactant solution were carried out. All simulations were performed using the GROMACS 5.1.1 simulation package.36 The simulations were run up to 200 ns depending on the time needed to reach equilibrium. Toluene molecules were represented by the united atom Optimized Potentials for Liquid Simulations (OPLS) force field,37 whereas asphaltenes and surfactants were modeled using all atom OPLS 38 since it has been proven that all atom alkane models with OPLS force field are able to reproduce density and heat of evaporation.39 Simulations were performed with NVT (i.e., constant Number, Volume, and Temperature) ensembles at 300 K using the Langevin thermostat.36 In these simulations, we modulated the pressure by using a semi hard sphere piston on top of the fluids at 1 bar. The cut off radii for Lennard-Jones and Columbic interactions were set to 1.4 nm.

3.

RESULTS AND DISCUSSION

3.1 3.1.1

Experimental Microemulsion formation

Figure 2 shows the HRTEM images of NAPL-in-brine microemulsions formed by maltoside and triton. Although the average size of both microemulsions were 800-1000 nm, there were two clear differences in their morphology. In microemulsions formed by maltoside, the NAPL phase was trapped in a central core surrounded by a thick shell of surfactant molecules. The shells contained self-associated maltoside molecules whose heads appeared as black dots. Some of the shells interacted with themselves to form a continuous phase. In contrast, triton generated well-dispersed microemulsions with NAPL with no discernible core and shell structure. This observation implied that triton is a better NAPL dispersant than maltoside.

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3.1.2

Wettability alteration

After aging in NAPL for a week, the wettability of Bentheimer and Arkose was altered from water-wet to oil-wet, with contact angles of 109 and 132, respectively. As expected, Arkose experienced more wettability alteration than Bentheimer since asphaltenes adsorbed more on carbonates than silicates.40,41 Figure 3 shows that the addition of maltoside and triton to brine was able to restore the wettability of aged Bentheimer substrates from weakly oil-wet to water-wet, with average contact angles of 64 and 75, respectively. The hydrophilic heads of both surfactants formed hydrogen bonds with quartz and helped desorb the organic layer, thereby increasing the wetting preference of the surface to water.42,43 Maltoside showed a superior ability to restore the wettability of Bentheimer due to its abundant hydroxyl groups in the sugar heads. In Arkose, triton and maltoside exhibited a similar wetting behavior with contact angles of 88 and 75, respectively. The bimodal distribution observed with maltoside may potentially indicate a relation between CA and pore size in Figure 1. In this case, maltoside may be more effective than triton in altering the wettability of smaller pores. The CA values provided earlier were, in fact, measured after 24 hours. To further assess the time variation of wettability, we plotted in Figure 4 the average static angles of NAPL droplets released from aged rocks during the first 7 hours of contact with brine solutions. The data indicated a faster decrease in CA with maltoside compared to triton in both sandstones, confirming the superior ability of this surfactant to rapidly imbibe into these rocks. 3.1.3

Spontaneous imbibition

The performance of the two surfactants was also examined by spontaneous imbibition tests on aged cores. In Bentheimer sandstone, the surfactant solutions exhibited faster NAPL recovery compared to brine since they could decrease the IFT by more than one order of magnitude and easily make its way into the pores (Figure 5). The ultimate amount recovered by triton was improved from 55% to 62%, which was mainly attributed to wettability restoration. Upon contact with surfactant molecules, the quartz surfaces became water-wet with favorable threshold capillary pressures. Therefore, brine could invade into a large fraction of the pores and leave less NAPL behind. Maltoside, which had the strongest hydrogen bonding ability with the silanol groups of quartz, restored wettability to a greater extent compared to triton and consequently recovered the largest amount of NAPL (68%). Arkose sandstone experienced more wettability alteration by NAPL due to the presence of carbonates. The unfavorable capillary pressures and smaller pore sizes made it harder for brine to invade into the pores and curbed the imbibition process, resulting in lower recovery rate and amount (30%) compared to Bentheimer.

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The strong ability of maltoside to reverse wettability enabled a more effective NAPL displacement especially in tight pores. Therefore, maltoside exhibited the fastest and largest amounts of NAPL removal (57%). 3.2 3.2.1

Simulation Single asphaltene molecules

Molecular simulations were first performed using single asphaltene molecules to determine their interactions with the mineral surface. Simulation trajectories revealed that water molecules were able to detach ASP1-3, and ASP5-6, and ASP9 from the mineral surface after 10 ns by surrounding the asphaltene molecule and forming of H-bonds with the surface. It took water molecules a longer time (~20 ns) to remove ASP9 due to its larger size and stronger interactions with the surface. In contrast, ASP7 and ASP8 remained pinned to the surface due to the interaction between their functional groups (sulfonic acid in ASP7 and carboxylic acid in ASP8) and the surface that the H-bonds formed by water molecules could not overcome (Figure 6 (a) and (b)). Surprisingly ASP4, which cannot form strong H-bonds with the surface, remained adsorbed on the surface for a relatively long time (~30 ns) and finally detached from the mineral surface by water molecules. This is likely due to the strong electrostatic interaction between calcium ion in the surface and sulfur monoxide group in ASP4 (Figure 6 (c)). Simulation of surfactant solutions alone revealed that maltoside molecules immediately started to selfassociate and form a cone-shaped connected channel, while triton molecules formed two separate phases at the brine and mineral surfaces after 40 ns. This could be verified by looking at the association energies between surfactant molecules. For triton, this energy was calculated to be 9,319 kJ/mol whereas for maltoside, it was three times greater (i.e., 29,750 kJ/mol). Although the number of triton molecules interacting with the surface was more than maltoside molecules, maltoside had a stronger coulomb interaction with the surface (512 kJ/mol) compared to triton (409.68 kJ/mol) due to the presence of -OH groups in its head that could form strong H-bonds. In order to understand these interactions in the presence of asphaltenes, surfactant molecules were introduced into the brine solution separately with ASP7 molecule adsorbed on the mineral surface. The simulation results indicated a distinguished ability of the two surfactants in removing this asphaltene from the surface, as shown in Figure 7. Maltoside, which has a greater number of -OH groups in its hydrophilic head, had a strong tendency to self-associate through H-bond formation. Therefore, after covering the brine surface, this surfactant immediately formed a stable cone-shaped channel inside the brine phase that connected the mineral to the brine surface. Triton, on the other hand, showed a much weaker selfassociation due to the fact that it only has one -OH group in its head. As a result, triton molecules that were 8


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not near the mineral surface remained mostly dispersed inside the brine. Simulation at longer times showed that the adsorbed asphaltene lied perpendicular to the surface in the presence of maltoside in order to maximize its interaction with the surfactant’s hydrophobic tails. In contrast, ASP7 remained parallel to the surface in the triton solution because triton molecules preferred to interact with asphaltene molecules rather than themselves or the mineral surface. Overall, the ability of maltoside to form a compact and stable channel and its strong Van der Waals interaction with asphaltenes resulted in the asphaltene molecule being pulled away from the mineral surface to increase asphaltenes/surfactant interaction surface area. However, this molecule remained closer to the mineral surface in triton. This observation was further confirmed by comparing the interaction energies between asphaltene molecules and the mineral surface with and without the presence of the two surfactants, as shown in Table 6. The energy values showed that maltoside decreased asphaltene/surface interaction energies to a higher extent than triton for all asphaltenes. These results were consistent with our experimental observations where maltoside had a better ability than triton to solubilize adsorbed DNAPLs from H-bonding rock surfaces and restore their wettability (Figure 3). Additionally, maltoside exhibited the strongest tendency for self-association and as a result could form a considerably thicker microemulsion shell phase around NAPL compared to triton (Figure 2) and a continuous channel between the mineral and water surfaces (Figure 7). 3.2.2

Polydisperse asphaltene molecules

The polydisperse DNAPL model was next solvated in toluene then placed on the mineral surface. The simulation was run long enough to reach equilibrium. The simulation results showed that asphaltene molecules formed a network of small nanoaggregates on the surface. Furthermore, asphaltene molecules with different structures had a different tendency to adsorb on the surface. The order of adsorption tendency of asphaltene molecules in the mixture did not change from individual simulations, i.e., ASP8 had the higher interaction while ASP1 had the lowest one. From the interaction energy values in Table 7, it can be concluded that asphaltene functional groups rather than molecular weight or aromaticity affect their surface interactions. Therefore, the nature of asphaltene-surface interaction is mainly electrostatic (polar interaction) instead of Van der Waals interactions. In order to evaluate the ability of surfactants to solubilize adsorbed asphaltene molecules, the mineral surface was extended in the y direction by 2.49 nm from each side. In this case, the NAPL phase formed a hemi-cylindrical shape on the mineral surface and the brine/surfactant solution was able to reach the mineral surface from the NAPL sides. The interaction energies between asphaltene molecules and mineral surface were calculated after 200 ns (Figure 8). Maltoside reduced the interaction energies between all asphaltene molecules and the surface to a larger extent than triton. This could be explained by analyzing the simulations trajectories. Figure 9 showed a connected dense surfactant channel phase was formed and extended from 9


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the NAPL droplet toward the brine surface, which was consistent with the experimental results. Furthermore, we observed the migration of smaller NAPL molecules, such as toluene and ASP1, to the brine surface through this channel. We would ultimately observe the migration of the heavier asphaltene molecules as well if the simulations were run for longer times. It is worth mentioning that triton increased the surface interaction energy of ASP7 instead of reducing it. This has been seen in the simulations with a single asphaltene molecule on the surface as well, where at the early stage of simulations triton molecules pushed the asphaltene molecule toward the mineral surface rather than pulling it up. The interaction energies between asphaltene and surfactant molecules revealed once more a greater interaction between asphaltene and triton compared to maltoside (Figure 8). To simulate flow in the system, water molecules were transmitted with a constant acceleration of 2.5 × 10-4 nm/ps2. Figure 10 showed interaction energies between the asphaltene molecules and the mineral surface after running the simulations for 100 ns. Maltoside reduced the interaction values between all the asphaltene molecules and the mineral surface to a much greater extent than triton. The simulation trajectories showed that maltoside molecules detached most of the asphaltene molecules from the surface and transferred them to the upper brine surface, whereas triton molecules were not able to remove asphaltenes (Figure 11). This could be explained by the strong self-association of maltoside molecules that did not allow the flow to scatter them in the brine phase, therefore, all of the surfactant molecules migrated to the brine surface and dragged asphaltene molecules with themselves. On the other hand, triton, with a weaker self-association, was not able to hold a dense phase like maltoside. Instead, some of the surfactant molecules migrated and covered the brine surface while the rest remained with asphaltene molecules on the mineral surface. The difference in the self-association tendency of these two surfactants was evident by looking at their self-association energies. The interaction energy of triton was calculated to be 25,345 kJ/mol while for maltoside molecules the interaction energy was 112,776 kJ/mol, which was five times greater than that of triton. Although, the qualitative comparison is similar to what we reported in the simulations with surfactant solutions on the mineral surface, the values of self-associations have changed due to the addition of the asphaltene mixture, which tended to interact with surfactant molecules. In addition, the presence of flow reduced the interaction energy between surfactant molecules. The solubilization of asphaltene molecules by maltoside could be verified by monitoring the interaction energies between the whole asphaltene mixture and the mineral surface during the simulations. Figure 12 revealed that maltoside had a better ability to reduce the interactions between asphaltenes and the mineral compared to triton, this effect was even more pronounced under flow conditions. At the end of the flow simulation with maltoside, asphaltene interaction energy reduced by 7 times, which indicated that most of the asphaltene molecules were removed from the surface. It is interesting to note that triton/mineral

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interactions increased during the flow simulation while maltoside/mineral interactions remained almost constant, as shown in Figure 13 (a). This was due to the fact that the flow scattered asphaltene molecules and made the surface more accessible to triton. This also indicated that triton molecules were not able to migrate to the brine surface. Additionally, the asphaltene self-association energies decreased during the flow simulations in the presence of both surfactants (Figure 13 (b)). This is because surfactants interacted with asphaltene molecules and slightly dispersed them. The energy reduction was greater with triton than maltoside because triton could infiltrate asphaltene molecules and reduce their interactions. This behavior is in accord with the HRTEM images in Figure 2 where maltoside kept the NAPL phase in the core of microemulsions whereas triton dispersed NAPL throughout this phase. In summary, our MD simulations revealed that maltoside was able to desorb asphaltene molecules from hydrogen-bonding minerals by forming a connected channel due to its self-association behavior, whereas triton remained dispersed in solution. This was in line with our experimental studies where maltoside could restore the wettability of silicate-rich surfaces to a higher extent than triton, resulting into more brine invasion into the pores and higher NAPL recoveries by spontaneous imbibition.

4.

CONCLUSIONS

The main conclusions of this study are summarized in the following: 

A polydisperse asphaltene model was used to simulate the wettability alteration of silicate-rich rocks by DNAPLs in crude oils. Asphaltene molecules with H-bonding ability interacted more with mineral surfaces, suggesting that adsorption is driven by polar interactions. Functional groups such as -COOH and -SOOH could pin asphaltenes to the surface and prevent them from desorbing.



Wettability restoration by nonionic surfactants involved the adsorption of these additives on sandstones, which increased with their ability to form hydrogen bonds with the silanol groups of quartz. Contact angle measurements confirmed that highly H-bonding surfactants (such as ndodecyl β-D-maltoside) could restore the wettability of sandstones to a higher extent than other surfactants.



The micellar solubilization of DNAPL by surfactants was promoted by surfactant self-assembly. Early stages of solubilization by n-dodecyl β-D-maltoside were successfully observed through large-scale molecular dynamics simulations. Due to their relatively strong H-bonding propensity, surfactant molecules could self-associate and form a continuous channel that interacted with

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asphaltenes and promoted their desorption from mineral surfaces. The thick surfactant phase eventually trapped asphaltenes in a central core to form the microemulsions seen by HRTEM. 

Spontaneous imbibition tests showed that highly H-bonding surfactants like n-dodecyl β-Dmaltoside enabled faster and larger amount of NAPL recovery compared to triton. The performance of these surfactants was more pronounced in tight rocks due to their ability to restore the wettability of small pores and better mobilize LNAPL.

5.

ACKNOWLEDGEMENT

The authors would like to thank Alchemy Sciences and the National Science Foundation (Career Award #1351296) for financial support, Dr. Mohammad Piri for the use of Loren supercomputer, and Elizabeth Barsotti for QEMSCAN analysis.

6. (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

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Sharma, M. K.; Shah, D. O.; Brigham, W. E. The Influence of Temperature on Surface and Microscopic Properties of Surfactant Solutions in Relation to Fluid Displacement Efficiency in Porous Media. AIChE J. 1985, 31 (2), 222–228. Qin, T.; Javanbakht, G.; Goual, L.; Piri, M.; Towler, B. Microemulsion-Enhanced Displacement of Oil in Porous Media Containing Carbonate Cements. Colloids and Surfaces A: Physicochemical and Engineering Aspects 2017, 530, 60–71. Javanbakht, G.; Arshadi, M.; Qin, T.; Goual, L. Micro-Scale Displacement of NAPL by Surfactant and Microemulsion in Heterogeneous Porous Media. Advances in Water Resources 2017, 105, 173– 187. Zhou, M.; Rhue, R. D. Screening Commercial Surfactants Suitable for Remediating DNAPL Source Zones by Solubilization †. Environmental Science & Technology 2000, 34 (10), 1985–1990. Paria, S.; Yuet, P. K. Adsorption of Non-Ionic Surfactants onto Sand and Its Importance in Naphthalene Removal. Industrial & Engineering Chemistry Research 2007, 46 (1), 108–113. Goual, L. Microemulsions and Uses Thereof to Displace Oil in Heterogeneous Porous Media. Provisional Patent 15/367,478, University of Wyoming, 2016. Somasundaran, P.; Zhang, L. Adsorption of Surfactants on Minerals for Wettability Control in Improved Oil Recovery Processes. Journal of Petroleum Science and Engineering 2006, 52 (1–4), 198–212. Kahlweit, M.; Busse, G.; Faulhaber, B. Preparing Nontoxic Microemulsions with Alkyl Monoglucosides and the Role of Alkanediols as Cosolvents. Langmuir 1996, 12 (4), 861–862. Rojas, O. J.; Stubenrauch, C.; Lucia, L. A.; Habibi, Y. Interfacial Properties of Sugar-Based Surfactants. Bio-Based Surfactants and Detergents: Synthesis, Properties and Applications, AOCS Press, Urbana 2009, 457–480. Zhang, L.; Somasundaran, P.; Maltesh, C. Adsorption Ofn-Dodecyl-β-d-Maltoside on Solids. Journal of Colloid and Interface Science 1997, 191 (1), 202–208. Standnes, D. C.; Austad, T. Wettability Alteration in Carbonates: Interaction between Cationic Surfactant and Carboxylates as a Key Factor in Wettability Alteration from Oil-Wet to Water-Wet Conditions. Colloids and Surfaces A: Physicochemical and Engineering Aspects 2003, 216 (1), 243– 259. Standnes, D. C.; Austad, T. Wettability Alteration in Chalk: 2. Mechanism for Wettability Alteration from Oil-Wet to Water-Wet Using Surfactants. Journal of Petroleum Science and Engineering 2000, 28 (3), 123–143. Liu, Q.; Yuan, S.; Yan, H.; Zhao, X. Mechanism of Oil Detachment from a Silica Surface in Aqueous Surfactant Solutions: Molecular Dynamics Simulations. J. Phys. Chem. B 2012, 116 (9), 2867–2875. Lowry, E.; Sedghi, M.; Goual, L. Molecular Simulations of NAPL Removal from Mineral Surfaces Using Microemulsions and Surfactants. Colloids and Surfaces A: Physicochemical and Engineering Aspects 2016, 506, 485–494. Kao, R. L.; Wasan, D. T.; Nikolov, A. D.; Edwards, D. A. Mechanisms of Oil Removal from a Solid Surface in the Presence of Anionic Micellar Solutions. Colloids and Surfaces 1988, 34 (4), 389– 398. Adler, J. J.; Rabinovich, Y. I.; Moudgil, B. M. Origins of the Non-DLVO Force between Glass Surfaces in Aqueous Solution. Journal of Colloid and Interface Science 2001, 237 (2), 249–258. van Duijvenbode, R. C.; Koper, G. J. M.; Böhmer, M. R. Adsorption of Poly(Propylene Imine) Dendrimers on Glass. An Interplay between Surface and Particle Properties. Langmuir 2000, 16 (20), 7713–7719. Javanbakht, G.; Sedghi, M.; Welch, W. R. W.; Goual, L.; Hoepfner, M. P. Molecular Polydispersity Improves Prediction of Asphaltene Aggregation. Journal of Molecular Liquids 2018, 256, 382–394. Javanbakht, G.; Goual, L. Mobilization and Micellar Solubilization of NAPL Contaminants in Aquifer Rocks. Journal of Contaminant Hydrology 2016, 185–186, 61–73. GRIFFIN, W. C. Calculation of HLB Values of Non-Ionic Surfactants. J. Soc. Cosmet. Chem. 1954, 5, 249–256. 13


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Saraji, S.; Goual, L.; Piri, M.; Plancher, H. Wettability of Supercritical Carbon Dioxide/Water/Quartz Systems: Simultaneous Measurement of Contact Angle and Interfacial Tension at Reservoir Conditions. Langmuir 2013, 29 (23), 6856–6866. Vega, C.; de Miguel, E. Surface Tension of the Most Popular Models of Water by Using the TestArea Simulation Method. The Journal of Chemical Physics 2007, 126 (15), 154707. Raiteri, P.; Gale, J. D. Water Is the Key to Nonclassical Nucleation of Amorphous Calcium Carbonate. J. Am. Chem. Soc. 2010, 132 (49), 17623–17634. Sedghi, M.; Piri, M.; Goual, L. Atomistic Molecular Dynamics Simulations of Crude Oil/Brine Displacement in Calcite Mesopores. Langmuir 2016, 32 (14), 3375–3384. Abraham, M. J.; Murtola, T.; Schulz, R.; Páll, S.; Smith, J. C.; Hess, B.; Lindahl, E. GROMACS: High Performance Molecular Simulations through Multi-Level Parallelism from Laptops to Supercomputers. SoftwareX 2015, 1–2, 19–25. Jorgensen, W. L.; Madura, J. D.; Swenson, C. J. Optimized Intermolecular Potential Functions for Liquid Hydrocarbons. Journal of the American Chemical Society 1984, 106 (22), 6638–6646. Jorgensen, W. L.; Maxwell, D. S.; Tirado-Rives, J. Development and Testing of the OPLS All-Atom Force Field on Conformational Energetics and Properties of Organic Liquids. J. Am. Chem. Soc. 1996, 118 (45), 11225–11236. Sedghi, M.; Goual, L.; Welch, W.; Kubelka, J. Effect of Asphaltene Structure on Association and Aggregation Using Molecular Dynamics. J. Phys. Chem. B 2013, 117 (18), 5765–5776. Thomas, M. M.; Clouse, J. A.; Longo, J. M. Adsorption of Organic Compounds on Carbonate Minerals. Chemical Geology 1993, 109 (1), 201–213. Buckley, J. S.; Liu, Y.; Monsterleet, S. Mechanisms of Wetting Alteration by Crude Oils. SPE Journal 1998, 3 (01), 54–61. Bui, K.; Akkutlu, I. Y.; Zelenev, A.; Saboowala, H.; Gillis, J. R.; Silas, J. A. Insights Into Mobilization of Shale Oil by Use of Microemulsion. SPE Journal 2016, 21 (02), 613–620. Kumar, K.; Dao, E. K.; Mohanty, K. K. Atomic Force Microscopy Study of Wettability Alteration by Surfactants. SPE Journal 2008, 13 (02), 137–145.

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Page 15 of 29 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

Energy & Fuels

Table 1. Physical properties of the cores employed in this study. Rocks

Diameter, inches

Length, cm

Porosity, %

Permeability, mD

Bentheimer

1

4.75-5.05

23.27-23.92

2759.5-3289.3

Arkose

1

4.82-5.09

16.22-18.24

17.96-25.92

Table 2. Mineral composition of the rocks based on QEMSCAN. Minerals

Percentage (%) Bentheimer

Arkose

Quartz

97.37

58.66

Calcite

0.03

2.86

Dolomite

-

24.74

Illite

-

3.11

Albite

-

1.86

Kaolinite

0.48

-

K-Feldspar

1.79

7.72

Chlorite

0.02

0.08

Others

0.31

0.97

15


Energy & Fuels 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

Page 16 of 29

Table 3. Properties of NAPL used in this study. NAPL (Crude oil) ρ20C (g/mL)

0.9214

Reflective Index at 20C

1.5222

Viscosity (mPa.s)

112.0

C (%)

85.07

H (%)

7.75

N (%)

1.09

O (%)

1.61

S (%)

4.63

H/C

1.1

Asphaltenes (wt%)

9.03

TAN* (mg of KOH/g)

1.69

TBN* (mg of KOH/g)

2.25

TBN/TAN

1.33

*TAN: Total acid number, TBN: Total base number.

Table 4. Properties of selected surfactants. Name

Structure

Triton X-100

HLB*

MW*

13.5

647

13.4

511

, n = 9-10 n-dodecyl β-D-maltoside

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Energy & Fuels

*HLB: Hydrophilic-lipophilic balance, MW: Molecular weight. Table 5. Molecular structures of asphaltenes used in the polydisperse model.29 MW, g/mol

Aromaticity

0.425

0.5

0.65

ASP1

ASP2

ASP3

ASP4

ASP5

ASP6

ASP7

ASP8

ASP9

500

750

1000

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Page 18 of 29

Table 6. Interaction energies between single asphaltene molecules and mineral surface in the presence of surfactants. Interaction energies (kJ/mol) Brine

Triton

Maltoside

ASP4

86.6

87.214

77.94

ASP7

175.9

231.8

148.62

ASP8

179.6

142.012

137.27

Table 7. Interaction energies between asphaltene molecules in polydisperse model and mineral surface. ASP1 ASP2 Interaction energies (kJ/mol)

273.8

ASP3

ASP4

ASP5

ASP6

ASP7 ASP8 ASP9

223.34 412.46 482.14 423.17 162.63 601.5

18


816.9

242.58

Page 19 of 29

0.2

2.00E-01

0.15

1.50E-01

f(r)

a)

f (r)

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

Energy & Fuels

0.1

1.00E-01

0.05

5.00E-02

0

0.00E+00 1

10

100

1

r (μm)

10

r (µm)

100

b)

c)

Figure 1. a) Pore size distribution, b) micro-CT image of core cross-section, c) mineralogy map of Bentheimer (left) and Arkose (right).

19


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(a) Maltoside

(b) Triton

Figure 2. HRTEM micrographs of NAPL-in-brine microemulsions with (a) maltoside and (b) triton.

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a) Bentheimer Maltoside

b) Arkose 60

Triton

50

50

40

40

Percent (%)

Percent (%)

60

30 20 10

Maltoside

Trition

30 20 10

0

0 0

50

100

Contact angle (degree)

150

0

50

100 Contact angle (degree)

150

Figure 3. Static contact angle distribution of NAPL droplets released from a) Bentheimer and b) Arkose after 24 hours in surfactant solutions.

a) Bentheimer

b) Arkose 160

160 Triton

Maltoside

Triton

140


Maltoside

140


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

Energy & Fuels

120

120

100

100 80 60

80 60 40

40 0

100

200 (mins) 300 Time

0

400

Time (mins)

Figure 4. Average dynamic contact angle during the first 7 hours of contact between surfactant solutions and aged a) Bentheimer b) Arkose.

21


Energy & Fuels

a)

Bentheimer

Maltoside

80

Triton

Brine

70

Oil recovery (%)

60 50 40 30 20 10 0 0

50

100

150 200 Time (hours)

b)

250

300

350

250

300

350

Arkose

80 70 60 Oil recovery (%)

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

Page 22 of 29

50 40 30 20 10 0 0

50

100

150 200 Time (hours)

Figure 5. Effect of triton and maltoside surfactants on oil recovery by spontaneous imbibition in a) Bentheimer and b) Arkose.

22


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Energy & Fuels

(a)

(b)

(c)

Figure 6. Interaction between surface and a) ASP7, through sulfonic acid group, b) ASP8, through carboxylic acid group, c) ASP4, through sulfur monoxide group.

23


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Maltoside

Page 24 of 29

Triton (a) 10 ns

(b) 100 ns

Figure 7. Interaction between ASP7 and mineral surface at early stage (a) and after reaching equilibrium (b) in the presence of maltoside (in red) and triton (in purple).

24


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1000 900 Interaction Energy (kJ/mol)

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

Energy & Fuels

Brine

Triton

Maltoside

800 700 600 500 400 300 200 100 0 ASP1

ASP2

ASP3

ASP4

ASP5

ASP6

ASP7

ASP8

ASP9

Figure 8. Interaction energies between asphaltene molecules and mineral surface in brine and surfactant solutions during static simulations.

25


Energy & Fuels 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

(a) Maltoside

(b) Triton

Figure 9. Snapshots of static simulations with a) maltoside, and b) triton. Color code: ASP1 gray, ASP2 green, ASP3 magenta, ASP4 yellow, ASP5 white, ASP6 pink, ASP7 purple, ASP8 orange, ASP9 red, triton ice-blue, maltoside light red, and toluene lime.

26


Page 26 of 29

Page 27 of 29

1000 900 Interaction Energy (kJ/mol)

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

Energy & Fuels

Brine

Triton

Maltoside

800 700 600 500 400 300 200 100 0 ASP1

ASP2

ASP3

ASP4

ASP5

ASP6

ASP7

ASP8

ASP9

Figure 10. Interaction energies between asphaltene molecules and the solid surface in brine and surfactant solutions during flow simulations.

27


Energy & Fuels 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

(a) Maltoside

Page 28 of 29

(b) Triton

Figure 11. Snapshots of flow simulations with a) Maltoside, and b) Triton. Color code: ASP1 gray, ASP2 green, ASP3 magenta, ASP4 yellow, ASP5 white, ASP6 pink, ASP7 purple, ASP8 orange, ASP9 red, triton ice-blue, maltoside light red. Toluene was deleted for clarity. 28


Page 29 of 29

8000

Start of flow

Interaction Energy (kJ/mol)

7000 6000

Simul ations

5000 4000 3000

Simulations with flow

2000 ASP-Calcite (Triton)

1000

ASP-Calcite (Maltoside)

0 0

20000

40000

60000

Time (ps)

80000

100000

120000

140000

Figure 12. Interaction energies between polydisperse asphaltene mixture and mineral surface in the presence of surfactants during simulations with and without flow.

(b)

(a) 1000

25000

900 800



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

Energy & Fuels

700 600 500 400 300 200

TRI-Calcite MAL-Calcite

100 0

20000 15000 10000 5000

ASP-ASP (Triton) ASP-ASP (Maltoside)

0 0

20000

40000

Time (ps)

60000

80000

0

20000

40000

Time (ps)

60000

80000

Figure 13. Interaction energies between a) surfactant molecules and mineral surface, and b) asphaltene molecules in the presence of surfactants.

29


Nanoscale Investigation of Surfactant-Enhanced Solubilization of

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