Evaluation of Chemicals Interaction with Heavy Crude Oil through

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Evaluation of Chemicals Interaction with Heavy Crude Oil through Water/Oil Emulsion and Interfacial Tension Study Ali Akbar Dehghan, Mohsen Masihi, and Shahab Ayatollahi Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 16 Sep 2013 Downloaded from http://pubs.acs.org on September 17, 2013

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Evaluation of Chemicals Interaction with Heavy Crude Oil through Water/Oil Emulsion and Interfacial Tension Study

A. A. Dehghan1, M.Masihi1,*, Sh. Ayatollahi 1

1

Chemical and Petroleum Engineering Department, Sharif University of Technology, Tehran, Iran

*Corresponding author e-mail: [email protected], [email protected] Tel: +98-711-6474602

Fax: +98-711-6473575

ACS Paragon Plus Environment

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Abstract A new-designed surfactant was formulated to tolerate the harsh conditions of oil reservoirs including high salinity of the formation brine and temperature. The specific emulsion and interfacial tension (IFT) behavior of this new surface active agent were investigated by performing emulsion stability tests, emulsion size analysis, and IFT behavior in the presence of four different types of alkalis. Image processing was utilized to analyze the droplet size distribution using microscopic images of the samples. The results show that depending on the composition of the mixtures, the optimum phase region and interfacial tension behavior change considerably. Solutions containing higher percentage of the surfactant (around 1wt%) show good emulsification capability at different salinities; however, adding any selected alkali to these mixtures reduces the optimum range of salinity tolerance. Mixtures of the surfactant and Triethanolamine exhibit optimum three-phase region at higher salinity conditions compared to other alkaline/surfactant solutions. Increasing the solution salinity reduces the IFT for surfactant solutions however by adding any alkalis the trend was reversed. Considering high values for solubilization-ratio, feasible size of the emulsion droplets, and low IFT values result in promising condition for more oil recovery using a chemical enhanced oil recovery process.

Keywords: Chemical Flooding, Surfactant, Heavy Oil, Alkaline, Emulsion

1. Introduction Water flooding of high viscosity oil reservoirs has been looked upon skeptically in the past because of expected low recoveries.1 This may explain the lack of fundamental studies of the influence of many microscopic parameters and viscosity ratio, viscosity of the displaced to the displacing fluid, on water flood recoveries at ratios greater than 100 to 1.1-3 As early as 1917, Squires 4 suggested the addition of alkali to the flooding water to obtain extra oil from underground rocks.4 At early time, however, the main function of water flooding additives was believed to be the removal of oil from solid surface.5 Later, it was recognized that the capillary force played an important role in the existence of residual oil after water flooding. Therefore, it is logical to seek chemicals by classifying the attempts to change the surface and interfacial forces and permit water to release oil more effectively by changing in rock wettability or reducing the oil/water interfacial tension which restrain the oil in the reservoirs from flowing out.6


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Injection of chemical solutions (including alkalis and surfactants) improves the oil recoveries by improvement in microscopic displacement efficiency. The injected alkaline chemicals not only have interactions with rock to change the wettability conditions, but also interact with oil to form emulsions which are favorable for improving oil recovery.7 The in situ formation of emulsions during alkaline flooding has been recognized as one of the effective methods to improve sweep efficiency for heavy oil recovery.8, 9,10 An alkali is a base which produces hydroxide ions (OH-) when dissolved in water or alcohol. The alkali compounds that have been considered for oil recovery can generate high pH and include sodium hydroxide, sodium carbonate, sodium silicate, sodium phosphate, ammonium hydroxide, etc.11-13 Oil recovery mechanisms in alkali flooding are complicated and at least eight postulated recovery mechanisms have been reported in the literature: These include emulsification with entrainment, emulsification with entrapment, emulsification with coalescence, wettability reversal, wettability gradients, oil-phase swelling, disruption of rigid films, and low interfacial tensions.1, 9, 14-21 In alkali flooding applications, the minimum oil-water IFT is often attained at very low concentrations of alkali. However, due to alkali losses from adsorption or precipitation in the porous media, higher alkali concentrations often need to be injected. This leads to floods being performed at conditions that are not optimal for recovery, thus, a mixture of alkali and surfactant is often injected in order to stabilize the flood at the optimum concentration for minimum IFT.9, 22, 23 Surfactants are energetically favorable to be located at the interface rather than in the bulk phase. 24 A surfactant molecule has at least one hydrophilic group and at least one hydrophobic group. Because of this character that can significantly lower the interfacial tensions and alter wetting properties, surfactants are considered as good enhanced oil recovery agents since 1970s. Surfactants, whether synthetic or soap molecules made by alkali, reduce the interfacial tension between water and oil. Surfactant solutions flooding is carried out with the purpose of reducing interfacial tensions between oil and water, thus improving the displacement efficiency. At the same time they produce an emulsion state which helps the better displacement of the injected solution. An emulsion is defined as dispersion of one liquid (internal or dispersed phase) within another (external or continuous phase) in the presence of surface-active agents (emulsifiers).7 For heavy oil, the viscosity of waterin-oil (W/O) emulsion is higher than that of the water and will result in better displacement. In other words, the key problem in heavy oil reservoir is inefficient sweep due to low mobility of the oil, not the residual oil in the swept region. If the injected alkali-surfactant solutions form oil-in-water (O/W) emulsions, the viscosity of these emulsions would be much lower than that of the original oil. Thus the bypassed oil can be emulsified at the tip


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of the water fingers, mobilized and produced at relatively low pressure gradients.25 The interfacial tension and emulsion behavior in this type of process is better described by examining the phase behavior of microemulsion systems. Important concepts and details on the phase behavior of such systems has been presented by Winsor.26 By emerging of successful new Enhanced Oil Recovery (EOR) technologies in the oilfields such as chemical flooding, emulsions receives more attention for fluid flow mechanism interpretation in real oil reservoirs. It was realized that emulsions generated in oil operations can lead to positive effects on oil recovery.27 With more ongoing laboratory work, many recovery mechanisms have been proposed, among which emulsion formation may be a viable hypothesis to explain the high pressure drop and mobility control by naturally occurring emulsions during chemical flooding in a porous media.28 Droplet size distribution (DSD) analysis provides useful information on the structure and stability of multiple emulsions, which are very important to characterize emulsion systems.29 It also enables the observation of the growth process of droplets dispersed in multiple emulsions. In order to describe the droplet size distribution, the value of two parameters (which define the droplet sizes) could be evaluated: the arithmetic mean diameter and the median diameter.30 The arithmetic mean diameter is sum of the each droplet diameter divided by the number of droplets. The median diameter is defined as the diameter that corresponds to a cumulative droplet frequency of 50%. The results are presented as histograms of the distribution density as well as by establishing the mean and the median diameter of the droplets. These information are necessary to monitor the emulsions stability and also help to describe multiple structure of these systems and to allow the quality and reproducibility control of the emulsification process.31 In this work, a new designed surfactant is evaluated for enhanced acidic heavy oil recovery from an underground oil reservoir. Two main mechanisms of chemical flooding including emulsion behavior and IFT reduction are studied here. Emulsion generation, emulsion stability, and emulsion droplet size analysis of the solutions prepared by this new surfactant and different alkalis were categorized using static bottle tests and microscopic observations. Spinning drop apparatus was used to measure the IFT values of the provided solutions. Having all the mentioned experimental results and analysis of the observed phenomena could be used to evaluate the suggested chemicals' performance and predict their possible positive application to displace a kind of acidic heavy oil in an underground reservoir.


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2. Experimental Work 2.1. Materials The following chemicals were used in the experiments: a newly designed anionic surfactant with a mixture including sulfonic acid, nonylphenol 10 mole ethoxylted, triethanol amine and isobutanol (called SURF1), four sets of alkalis (Sodium Hydroxide (NaOH), Sodium Carbonate (Na2CO3), Sodium Metaborate (NaBO2), and Triethanolamine (TEA)) provided by the MERCK company, and Sodium Chloride to make saline water. Many preliminary experiments have been done to find the ultimate suitable composition of the surfactant. The designed surfactant was a combination of four different components which makes it compatible with high saline formation waters, more soluble in brine containing divalent cations, and high temperature tolerant; a mutual solvent as a co-surfactant was also included in its composition to increase the dissolution and dispersion of its additives. This blend has good solubility behavior without forming liquid crystals or gels. It can be injected as a single phase solution (in solutions containing an alkali and polymer) at relevant temperature and at high salinities so that highly viscous phases will be avoided. The physicochemical properties of this new surfactant is presented in Table 1. The crude oil used in our experiments was obtained from an Iranian heavy oil reservoir with 19º API and a viscosity of 350 cp at 25º C. Its asphaltene content was approximately 14% and its acid number was 1.25 mg KOH/gr oil, which made it a potential candidate for chemical flooding.

2.2. Experimental Procedures The bottle test has been proved to be a straightforward and easily operated method with wide application for water/oil emulsion related experiments. The stability of the emulsion is generally related to the ease of water separation with time and demulsifier concentration. In order to study the emulsion behavior of the aqueous-oil system based on any of the surfactants, the emulsion stability tests were done for different sets of chemicals. In this paper, the results of various static bottle tests at water to oil ratio (WOR) of 9:1 present; the WOR were kept constant at this step to find a possible trend by changing the chemical composition of alkalis and surfactant at different salinities. For each set of experiments around 21 days was considered to get the final equilibrium state. The emulsion separation index (ESI) of the provided mixtures in the first 2-3 Hrs were also drawn and compared. The trend of the stabilization was drawn to show how the composition of the chemicals might affect


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the interaction behavior of the mixture in a short period. The droplets’ size and their size distribution at optimum states were found by taking and analyzing the microscopic pictures. The IFT measurements were done by spinning drop device; the IFT values for each set of the provided solutions made by chemical mixtures and the crude oil at different salinities were measured at a constant rotational speed of 6000 rpm and monitored during a time interval.

3. Results and Discussions In order to find the emulsion behavior of the SURF1 and its alkaline mixtures with crude oil, more than 86 sets of bottle tests were carried out. The goal in these sets of experiments was to find the optimum salinity, the solubilization ratio (SR), and emulsion separation index for the provided chemicals as well as comparing the effect of alkalis on SURF1 functionality. The size distribution of the produced emulsion droplets at various provided mixtures were also analyzed. To explore the IFT trend of the chemical mixtures with the crude oil and their possible synergistic effect, more than 45 experiments were done and the results were analyzed and compared. Before starting the solution preparation, the compatibility of the surfactant with hard ions was analyzed and the results showed good compatibility performance without any precipitation after its contact with brine containing hard ions.

3.1. Emulsion Behavior of the Surfactant Solutions To find the SURF1 individual effect on aqueous-crude oil emulsion behavior, 14 sets of bottle test experiments were done. The surfactant concentration and the salinities were changed to investigate the solution emulsion behavior. The overall results showed that at lower SURF1 concentration and lower solution salinities the separation process takes place faster which demonstrate the lower emulsion existence chance in the solution. This is mainly because of the weakening of the electrical double layers between the oil droplets and the aqueous phase; since very little brine’s ion concentration in the media reduces the holding strength of the suspended emulsion droplets the stability time decreases and the separation process happens faster. This process also happens at very high salinity values, consequently a normal range of salinity is required based on each chemical composition. The solubilization parameter Vo/Vs is defined as the volumetric ratio of solubilized oil to surfactant, and Vw/Vs is water to surfactant in the microemulsion phase. At optimum salinity, the amount of oil and brine solubilized


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in the surfactant phase are approximately equal which is also another definition of optimum salinity.32 The optimum salinity for the SURF1-water-crude oil mixture occurred at salinity of 150000 ppm and at quite high SURF1 concentration. The solubilization ratio (SR) for this solution at 150000 ppm is 28 which shows a promising factor for its application. This is mainly because of the heavy/acidic nature of the crude oil and specific design of the SURF1. Presence of an ethoxylate group and alkaline component in the surfactant formula brings a salinity tolerance for it in the solution. The emulsion separation index graph for the optimum set mixtures and their solubilization ratio diagram are shown in Figures 1 and 2, respectively. The oil in water emulsion state at optimal condition for SURF1 was quite light. This means that the expected emulsion viscous behavior for this individual solution wouldn't be so motivating in the porous media. However presence of the three phase region at high salinity which confirms the Winsor III type of the solution is demonstrating the low IFT region at this state; this will improve the microscopic oil displacement efficiency at real reservoir condition. The ionic nature of the SURF1 mixture and its specific chemical composition provides a particular range of solution salinity for its proper application. At low salinity values, no emulsion generation tendency was observed for the SURF1 solutions even increasing the surfactant concentration did not affect its behavior. However at higher salinities increasing the SURF1 concentration could be very effective on emulsion generation tendency of the solutions and the separation process did not happen quickly. The emulsion separation index and the separation process trends were shown in Figures 3 to 6. The fact that at higher salinity more hydrophilic behavior was observed for SURF1 is an indicator of charge balance importance for its solutions.

3.2. Fish Phase Diagram Also the effects of SURF1 mixture concentration in different brine solutions were studied by constructing fish phase diagram, Figure 7,where the middle phase microemulsion (Winsor III) is formed with wide ranges (0.8 wt% - 6 wt%) of the surfactant concentration. Fish phase diagram was developed to find the effect of salt concentration on the phase behavior of brine/surfactant/oil system.33,

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According to salinity scan, systems

containing more than 0.8 wt% of SURF1 showed matches with conventional Winsor I, III, II transitions at experimental conditions where the optimal salinities were obtained between 130000 to 165000 ppm of NaCl concentration.


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The designed surfactant is mainly ionic and highly affected by the solution salt concentration. At lower salt concentrations the SURF1 solution mixture is soluble in water and forms micelles which coexist with excess oil, this phase is considered as Winsor I; so SURF1 is more hydrophilic at this point. On the contrary at higher salt concentration, the non-aqueous reversed micellar solution coexist with an excess water phase (Winsor II) because of increasing the lipophilic properties of SURF1. Between these two salinity ranges, an intermediate phase including all three phases of water, surfactant and oil presents at hydrophilic-lipophilic balanced point (HLB). This region is called the middle phase and contains the total amount of the solution surfactant. The surfactant range in the middle phase was from 0.9 to 6 wt% at various salt concentrations; this wide range of three-phase region at high salinity domain demonstrates a unique performance of this surfactant owing to its special chemical composition.

3.3. Emulsion Behavior of Alkali-Surfactant Solutions Various mixtures of the SURF1 and any of the four selected alkalis including Sodium Hydroxide (NaOH), Sodium Carbonate (Na2CO3), Sodium Metaborate (NaBO2), and Triethanolamine (TEA) were provided to find out how the emulsion generation ability and stabilization of this surfactant could be affected. In all the experiments, 0.2 wt% of SURF1 was dissolved in the solutions to preserve the economical aspect of the surfactant concentration in real alkaline-surfactant flooding conditions. The emulsion separation index for all the mixtures of the surfactant-alkali was obtained and compared. Also the concentration of each alkali in a constant surfactant-concentration media was changed to observe its individual effect. The preliminary results showed that by increasing Sodium hydroxide concentration in the solutions the separation process occurred faster; this phenomenon was observed for almost all the alkali addition cases. Although the presence of the alkali in the media could moderate the oil-water mixing tendency by generating some in-situ soaps, the excess amount of these materials reduces the interfacial film stability of the emulsions and causes a faster separation process. This effect was more dominant at higher salinity solutions in which more cationic/anionic charges are accumulated. In another word, as NaCl concentration increases, the beneficial effect of the alkalis is reduced, presumably because the screening effect of the additional electrolyte decreases electrostatic repulsion between surfactant ions in solution and the calcite surface. Better demonstration of this phenomenon is presented in Figures 8 and 10 for Sodium hydroxide case at two NaCl concentrations of 30000 and 100000 ppm. Sodium Carbonate, however, represented a more severe effect


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on emulsion separation index of SURF1; adding variable amount of this alkalis considerably reduced the separation time at lower salinities while quite the same results was obtained at higher salinity values (Figures 9 and 11). The interesting point was at 0.1 wt% of sodium carbonate concentration; at this solution a three phase solution was observed representing its optimum performance at this conditions. However, having extra concentration of this alkali caused a quite fast separation. This was mainly because of the higher cationic/anionic charge concentration in its solution. The same set of tests was performed for the solutions made by adding each of Sodium Metaborate and Triethanolamine as the alkali. The trends of the emulsion separation index graph were quite the same as Figures 8 to 11; however the separation time was quite longer for TEA mixtures (around 10-20 minutes) at lower salinities. Perhaps the acid-base reaction of these alkalis with the carboxylic groups in the crude oil structure generates extra in-situ surfactant in the solution, results in droplets stability at lower salinities. However, increasing the solution charges at higher salinities along with alkali extra ion concentration reduces the strength of the emulsion droplets stability in the solution and enforces them to coalesce in the form of separate phases. In order to decrease the number of variables and to have a comparison criterion, a series of experiments were designed so that SURF1 and each alkali concentrations in all of them were 0.2 wt% and 0.5 wt%, respectively. Changing the NaCl concentration in the solutions demonstrate the optimum phase region for each case. The results showed that the optimum salinity for Sodium Hydroxide, Sodium Carbonate, Sodium Metaborate, and Triethanolamine occurred at 20000, 23000, 33000, and 50000 ppm respectively. This behavior show that adding any alkali could provide a three phase region for a mixture having a few amount of SURF1 (0.2 wt%), however their optimum values are different. All the alkalis have the capability of generating some in-situ soap by reaction with crude oil carboxylic groups but the extent of reaction and the final electrolyte concentration are important to the final results. Measuring the pH values, which were 12.5,11,10.5, and 10 for NaOH, Na2CO3, NaBO2, and TEA respectively, of the solutions at their optimum salinity showed that their values varies quite in the same order of their three phase regions' salinities. It means that more electrolyte concentration presents in higher pH solutions that decreases electrostatic repulsion between surfactant ions in solution and the alkali surfaces. The solubilization ratio (SR) of these mixtures were also calculated by finding the ratio of the water/oil volumes to synthetic surfactant volume before and after the three phase region based on the bottle test experiments. In these sets of experiments 0.5 wt% of any alkali and 0.2 wt% of surfactant was retained and the salinity was


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changed. These values were found as 17, 16, 20, and 25 for NaOH, Na2CO3, NaBO2, and TEA respectively as they are shown in Figures 12 to 15. The final results (as they are shown in Figures 12 to 15) for Sodium hydroxide and Sodium Carbonate were close to each other in solutions including SURF1. Having a solubilization ratio of 17 and 16 for NaOH and Na2CO3 was an indicator of their quite similar ability to disperse an amount of oil in water phase at optimum state. The greater values for this parameter as it was obtained for two other alkalis shows their greater capability of dispersing oil droplets in the middle phase. Higher SR values could be an effective indicator for oil transportation in the porous media during chemical flooding since lower IFT values would be resulted at this state. The synergistic effect of the in-situ generated soaps as a result of alkalis reaction with acidic components of the crude oil and the synthetic surfactant generation was the main reason for the application of the alkalis. Based on the experiments all the alkalis could provide an optimum three phase solution with low concentration of surfactants which represented the positive interaction of the used chemicals. It is believed that the heavy nature of the provided crude oil and its high asphaltene content had also considerable effect on the stability of the emulsion droplets. Asphaltene molecules have negative charges and could absorb into surfactant films surrounding the dispersed oil/water droplets and affect the solution emulsion stability. In another word, this is due to the polar nature of the asphaltene materials and the presence of the electrical charge difference at oilwater interfaces that might absorb the asphaltene particles and improve the stability of the emulsions.

3.4. Interfacial Tension of the Chemical Solutions Interfacial tension and pH values of the provided solutions for both of the SURF1 and alkali-surfactant mixtures were measured by spinning drop apparatus. It was clear that adding small amount of the surfactant could drastically reduce the interfacial tension between the crude oil and aqueous solution. As it is shown in Figure 16, by increasing the solution salinity the IFT value for a brine solution containing just SURF1 decreases. Although the PH values did not considerably change, the IFT values decreased around one order of magnitude by doubling the SURF1 concentration at lower salinities; however, at higher SURF1 concentration this trend was not observed. So, based on the results it was found that the IFT between oil and water are sensitive to both SURF1 concentration and salinity, and the minimum IFT can be obtained in the solutions with salinity range of 50000 to 200000 ppm with various SURF1 concentrations. Once again, it was found that the electrolyte


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concentration has considerable affect on the mass transfer and interfacial equilibrium state between oil and aqueous solution. Pure alkalis effect on IFT behavior of crude oil and aqueous phase was studied by designing a series of experiments with variable alkali concentration and constant brine salinity. As it is shown in Figure 17, there is a critical alkaline concentration for their proper effective application. In almost all the cases, an upward IFT trend was observed after 0.1 wt% of each alkali concentration and the equilibrium IFT value was increased as the amount of each alkali raised. As alkalis concentration increases, their beneficial effect on system IFT value reduces, presumably, because the screening effect of the additional electrolyte decreases the electrostatic attraction between two phases; reducing the interfacial elasticity after this region reverts the IFT trend and the raises the tension between the phases. The possible synergistic effect of the alkalis-SURF1 solutions was studied by measuring the IFT values in the mixtures as mentioned in previous section such that SURF1 and each alkali concentrations in all of them were 0.2 wt% and 0.5 wt%, respectively. Interesting results of these set of experiments are shown in Figure 18. The trend of IFT variations showed that the alkalis have the dominant effect on the solution behavior. There was a minimum value in all the cases that increased as solution salinity raised. Although the obtained IFT values are not exactly representing those values at the optimum phase, their variation trend seems to be realistic such that the minimum value was obtained at salinities very close to the obtained optimum salinities of each solution and after that the IFT values raises gradually. The reason for this behavior is that there is an optimum region for electrostatic forces by charge balances in the solution then as salinity increases, the beneficial effect of each alkali is reduced, apparently because the screening effect of the additional electrolyte decreases positive electrostatic forces imposed by surfactants on the interfacial films to additionally separate the phases.

3.5. Granulometric Analysis of the Emulsion Droplets The microscopic analysis was carried out in order to visualize and notice the dimension variation of the multiple droplets in different solutions. This analysis was performed using an optical microscope with a polarimeter connected to a computer in order to obtain images and to measure the droplet sizes. The microscopic examination was made after solution stabilization and formation of the three phase regions. A drop from the emulsion solution was put on a cover slip to be observed under the microscope and 5 representative locations were selected for image capturing of the respective sample. An Olympus BX51 transmitted-light microscope


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with 0.5 μm resolution was used to capture digital images. At least two samples from each test tube were observed under the microscope, and several images were taken from each slide for analysis. A minimum of 1500 droplets from each emulsion solution at a specific time were then imaged so that digitally distinct droplets with sufficient contrast to be obtained. To count these droplets and find DSD parameters, Image-Pro software was used. Analysis of the results show that: 

Emulsion droplets are very fine in almost all the cases such that the majority of them are less than 1.5 µm in diameter. Only for the solutions made by Sodium Carbonate, the values are larger and grows up to 6 µm.



ranking of the solution shows that the finest droplets are with NaBO2 solution and the coarser ones are with Na2CO3 solution (both of the median and arithmetic diameters for all the solutions are shown in Table 2 ).

The reason for such a phenomenon, although the differences are not very influential, is the presence of the weaker interfacial film complexes around the emulsion droplets in the solutions with higher degree of alkalinity and stronger ion charges; this may allow water molecular transfer to the internal side of the interfacial area. A representative microscopic picture for each solution is presented in Figure 19.

4. Conclusions Based on the experimental results and analysis of the observations, it was found that the SURF1 was compatible with high salinity brines and its best phase behaviour was noticed at 150000 ppm of brine salinity for 1% surfactant concentration. While wide ranges of three phase region, good emulsion behavior, and low IFT region were observed for SURF1 solution, addition of the alkalis did not improve its optimum salinity values. There is a certain value for the alkali concentrations to improve the performance of the solutions such that increasing the alkaline concentration decreases the optimum salinity of the solution for all the cases tested in this study. On the other hand, adding alkali to SURF1 solution reduces the minimum IFT region to lower salinity values which was mainly because of the special composition of the SURF1 and the accumulation of the electrolyte concentration at the interface (at very high salinities, greater than 220000 ppm, the solution IFT values started to increase while at lower salinity solutions there is much wider low IFT region in alkali-surfactant system). The comparative study of the mean and median diameters of multiple droplets indicates that the prepared emulsions are well dispersed at their final stable conditions. The multiple features and the spherical form of the dispersed


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droplets with homogenous distribution were also proved by optical microscopy analysis. These two along with the measured size of the produced emulsions showed the low chance of major phase trapping in an oil reservoir.

Acknowledgements The authors would like to acknowledge the help of the Iranian Offshore Oil Company -Research and Technology Department- for the financial support of this work and the permission to publish the results.

References (1) Scott, G.R., Collins, H.N., and Flock, D.L., Improving Water flood Recovery of Viscous Crude Oils by Chemical Control, 1965, JCPT, Volume 4, Number 4, pp 243-251, DOI 10.2118/65-04-10 (2) Adams, D. M., Experiences with Water flooding Lloydminster Heavy-Oil Reservoirs, J. Pet. Tech. , 1982, Vol. 34, No. 8, pp. 1643−1650. (3) Miller, K. A., State of the Art of Western Canadian Heavy Oil Water Flood Technology, 2005, paper ID 2005-251 presented at the Canadian International Petroleum Conference, Calgary, Canada, DOI 10.2118/2005-251. (4) Squires, F., Method of recovering oil and gas, 1917, U.S. Patent No. 1,238,355. (5) Nutting, P. G., Chemical Problems in the Water-driving of Petroleum Reservoirs, 1925, Ind. Eng. Chem., Vol. 17, pp.1035–1036. (6) Taber, J.J., Research on enhanced oil recovery: past, present and future, Surface Phenomena in Enhanced Oil Recovery, 1981, Shah, D.O. (ed.), 13−52, Plenum Press, New York City. (7) Alvarado, D. A., The Flow of Macroemulsion through Porous Media; Ph.D. Thesis, 1975, Department of Petroleum Engineering, Stanford University, Stanford, California. (8) Jennings, H. Y., Johnson, C. E., and McAuliffe, C. D., A Caustic Water flooding Process for Heavy Oils, 1974, J. Pet. Tech., pp. 1344–1352. (9) Bryan, J. and Kantzas, A., Enhanced Heavy-oil Recovery by Alkali-Surfactant Flooding, 2007, SPE 110728, November 11–14, DOI: 10.2118/110738-MS.


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(10) Liu, Q., Dong, M., Yue, X., Houb, J., Synergy of alkali and surfactant in emulsification of heavy oil in brine, 2006, Colloids and Surfaces A: Physicochem. Eng. Aspects 273, pp. 219–228, doi:10.1016/j.colsurfa.2005.10.016. (11) deZabala, E. F., Vislocky, J.M., Rubin, E., Radke, C.J., A Chemical Theory for Linear Alkaline Flooding, 1982, SPEJ, vol 22, No 2, 245-258, DOI 10.2118/8997-PA. (12) Ramakrishnan, T. S., and Wasan, D. T., A Model for Interfacial Activity of Acidic Crude Oil/Caustic Systems for Alkaline Flooding, 1983, SPEJ, Vol. 23, No. 4, pp. 602-612, DOI 10.2118/10716-PA. (13) Lake, L. W., Enhanced Oil Recovery, 1989, Prentice-Hall, Englewood Cliffs, NJ. (14) Wagner, O. R., and Leach, R. O., Improving oil displacement efficiency by wettability adjustment, 1959, Trans. AIME, Vol. 216, pp. 65–72. (15) Cooke, J.R., C.E., Williams, R.E. and Kolodzie, P.A., Oil Recovery by Alkaline Waterflooding, 1974, Journal of Petroleum Technology, Vol. 26, No. 12, pp. 1365-1374. (16) Ehrlich, R, and Wygal, R. J., Interrelation of Crude Oil and Rock Properties with the Recovery of Oil by Caustic Water flooding, 1977, SPEJ, Vol. 17, No. 4, pp. 263-270. (17) Olsen, D. K., Hicks, M. D., Hurd, B. G., Sinnokrot, A. A., and Sweigart, C. N., Design of a Novel Flooding System for an Oil-Wet Central Texas Carbonate Reservoir, 1990, SPE 20224, presented at the SPE Seventh Symposium on Enhanced Oil Recovery, Tulsa, USA, DOI 10.2118/20224-MS. (18) Mayer, E. H., Berg, R. L., Carmichael, J. D., and Weinbrandt, R. M., Alkaline Injection for Enhanced Oil Recovery-A Status Report, 1983, Journal of Petroleum Technology, pp. 209- 221. (19) Mcauliffe, C.D., Oil-in-Water Emulsions and Their Flow Properties in Porous Media, 1973, Journal of Petroleum Technology, Vol. 25, No. 6, pp. 727-733. (20) Thomas, S., Farouq Ali, S.M., Scoular, J.R. and Verkoczy, B., Chemical Methods for Heavy Oil Recovery, 2001, Journal of Canadian Petroleum Technology, Vol. 40, No. 3, pp. 56- 61. (21) Santanna, V.C., Curbelo, F.D.S., Castro Dantas, T.N., Dantas Neto, A.A., Albuquerque, H.S., Garnica, A.I.C., Microemulsion flooding for enhanced oil recovery, 2009, Journal of Petroleum Science and Engineering 66, pp. 117–120, doi:10.1016/j.petrol.2009.01.009.


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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

(22) Nelson, R.C., Lawson, J.B., Thigpen, D.R. and Stegemeir, G.L., Cosurfactant-Enhanced Alkaline Flooding, 1984, SPE 12672 presented at the SPE Enhanced Oil Recovery Symposium, Tulsa, USA, DOI 10.2118/12672-MS. (23) Aoudia, M., Al-Maamari, R. S., Nabipour, M., Al-Bemani, A.S., Ayatollahi, Sh. Laboratory Study of Alkyl Ether Sulfonates for Improved Oil Recovery in High-Salinity Carbonate Reservoirs: A Case Study, Energy & Fuels Journal, 2010, vol. 24, pp. 3655–3660. (24) Miller, C. A., and Neogi, P., Interfacial Phenomena, 1985, Surfactant Science Series, V. 17, Marcel Dekker, Inc., New York. (25) Liu, Q., Dong, M., Ma, S., Tu, Y., Surfactant enhanced alkaline flooding for Western Canadian heavy oil recovery, 2007, Colloids and Surfaces A: Phys/Chem. Eng. Aspects, Vol. 293, pp. 63-71. (26) Friberg, S.E., Bothorel, P. Microemulsions: Structure and Dynamics, 1987, CRC Press, Boca Raton, pp. 219. (27) Sjöblom, J., Emulsion and Emulsion Stability, 2006, Second Edition; Taylor & Francis. (28) Kokal, S., Crude Oil Emulsions: A State-Of-The-Art Review, 2005, SPE Production & Facilities J., Vol. 20, No. 1, pp. 5–13. (29) Moradi, M., Alvarado, V., Huzurbazar, S., Effect of Salinity on Water-in-Crude Oil Emulsion: Evaluation through Drop-Size Distribution Proxy, 2011, Energy Fuels, 25, pp. 260–268 : DOI:10.1021/ef101236h. (30) Kawashima, Y., Hino, T., Takeuchi, H., Niwa, T., Horibe, K., Shear-induced phase inversion and size control of water/oil/water emulsion droplets with porous membrane, 1991, J. Colloid Interf. Sci., Vol 145, Issue 2, pp. 512–523. (31) Ursica L., Tita D., Palici I., Tita B., Vlaia V., Particle size analysis of some water/oil/water multiple emulsions, 2005, Journal of Pharmaceutical and Biomedical Analysis, Vol. 37, pp. 931–936. (32) Reed, R. L., and Healy, R. N., Contact Angles for Equilibrated Microemulsion Systems, 1984, SPEJ, pp. 342-350.


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(33) Shinoda, K. and Kunieda, H., The effect of salt concentration, temperature, and additives on the solvent property of aerosol at solution, 1987, Journal of Colloid and Interface Science, Vol. 118, No. 2, pp. 586-589. (34) Kayali, I., Qamhieh, K., Olsson, U., Microemulsion phase behavior of aerosol-OT combined with a cationic hydrotrope in the dilute region, 2010, Journal of Dispersion Science and Technology, Vol. 31, No. 2, pp. 183- 187. doi:10.1080/01932690903110293


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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

Figure Captions Figure 1: Emulsion stability tests at 150000 ppm salinity and different SURF1 concentration. Figure 2: Solubilization ratio diagram for SURF1 (1%) at changing water salinity conditions. Figure 3: Emulsion stability tests at 30000 ppm salinity and different SURF1 concentration (0.1 to 1 wt%). Figure 4: Emulsion stability tests at 30000 ppm salinity and different SURF1 concentration (1 to 6 wt%). Figure 5: Emulsion stability tests at 100000 ppm salinity and different SURF1 concentration (0.05 to 0.5 wt%). Figure 6: Emulsion stability tests at 100000 ppm salinity and different SURF1 concentration (1 to 6 wt%). Figure 7: Phase diagram of SURF1 solution in brine/crude oil (9:1 volume ratio), as a function of salt concentration. Figure 8: emulsion separation index at 30000 ppm salinity, 0.2% of SURF1, and various NaOH concentrations. Figure 9: emulsion separation index at 30000 ppm salinity, 0.2% of SURF1, and various Na2CO3 concentrations. Figure 10: emulsion separation index at 100000 ppm salinity, 0.2% of SURF1, and various NaOH concentrations. Figure 11: emulsion separation index at 100000 ppm salinity, 0.2% of SURF1, and various Na2CO3 concentrations. Figure 12: Solubilization ratio diagram for NaOH solution (0.5 wt% NaOH and 0.2% SURF1). Figure 13: Solubilization ratio diagram for Na2CO3 solution (0.5 wt% Na2CO3 and 0.2% SURF1). Figure 14: Solubilization ratio diagram for NaBO2 solution (0.5 wt% NaBO2 and 0.2% SURF1). Figure 15: Solubilization ratio diagram for TEA solution (0.5 wt% TEA and 0.2% SURF1). Figure 16: Interfacial tension and PH variation between 0.1, 0.2, and 1 wt% SURF1 concentration in aqueous solution and the crude oil at variable salinities. Figure 17: Interfacial tension and PH variation of four Alkaline solutions at 100000 ppm salinity.


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Figure 18: Interfacial tension and PH variation of the solutions with 0.5 wt% alkaline and 0.2 wt% SURF1 at various salinities. Figure 19: Initial microscopic images of the alkali-surfactant solutions: (a) solution with SURF1(0.2%), NaOH, (0.5%) (b) SURF1(0.2%), Na2CO3(0.5%), (c) SURF1(0.2%), NaBO2(0.5%), and (d) SURF1(0.2%), TEA(0.5%).


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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: Physicochemical properties of the SURF1.

Parameter

Unit

Standard Method

Value

Cloud Point

ºC

ASTM-D97

-14

Flash Point

ºC

ASTM-D93

42.7

Boiling Point

ºC

ASTM-D1120

91.5

Vapor Pressure

psi

ASTM-D323

1.5

Viscosity @ 20 ºC

CSt

ASTM-D445

65.8

Table 2: Emulsion droplet size specifications for the alkali-surfactant mixtures. Chemicals in the Solution

Salinity

Median Diameter

Arithmetic Mean Diameter

(wt%)

(ppm)

(µm)

(µm)

SURF1(0.2%), NaOH(0.5%)

20000

1.653

0.750

SURF1(0.2%), Na2CO3(0.5%)

23000

6.578

2.211

SURF1(0.2%), NaBO2(0.5%)

33000

0.490

0.272

SURF1(0.2%), TEA(0.5%)

50000

0.5467

0.4167


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100 90 80 70 60 50 40 30 20 10 0

Surf1=0.5% Surf1=1% Surf1=2% Surf1=3% Surf1=4% Surf1=5%

0

20

40

60 80 Time(min)

100

120

140

Figure 1

Solubilization Ratio (cc/cc)

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

Hw/H(total)

Energy & Fuels

35

35 Vo/Vs Vw/Vs

30 25

30 25

20

20

15

15

10

10

5

5 0

0 0

5

10 15 20 25 NaCl Concentration (wt %)

30

35

Figure 2


20

100 90 80 70 60 50 40 30 20 10 0

Surf1=0.1% Surf1=0.2% Surf1=0.4% Surf1=0.6% Surf1=0.8% Surf1=1% 0

20

40 60 Time (min)

80

100

Figure 3

Hw/H(total)

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

Hw/H(total)

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100 90 80 70 60 50 40 30 20 10 0

Surf1=1% Surf1=2% Surf1=3% Surf1=4% Surf1=5% Surf1=6% 0

20

40

60 80 Time(min)

100

120

140

Figure 4


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100 90 80 70 60 50 40 30 20 10 0

Surf1=0.05% Surf1=0.1% Surf1=0.2% Surf1=0.3% Surf1=0.4% Surf1=0.5%

0

20

40

60 80 Time(min)

100

120

140

100

120

140

Figure 5

Hw/H(total)

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

Hw/H(total)

Energy & Fuels

1 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0

Surf1=1% Surf1=2% Surf1=3% Surf1=4% Surf1=5% Surf1=6%

0

20

40

60 80 Time(min)

Figure 6


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180,000 Winsor II

170,000 Salinity (ppm)

160,000 150,000

Winsor III

140,000 130,000 120,000

Winsor I

110,000 100,000 0

1

2

3 4 5 6 7 8 Surfactant Concentration (wt%)

9

10

Figure 7

Hw/H(total)

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

100 90 80 70 60 50 40 30 20 10 0

NaOH=0.1% NaOH=0.2% NaOH=0.4% NaOH=0.6% NaOH=0.8% NaOH=1%

0

20

40 60 Time (min)

80

100

Figure 8


23

100 90 80 70 60 50 40 30 20 10 0

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Na2CO3=0.1% Na2CO3=0.2% Na2CO3=0.4% Na2CO3=0.6% Na2CO3=0.8% Na2CO3=1%

0

20

40

Time (min)

60

80

100

Figure 9

Hw/H(total)

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

Hw/H(total)

Energy & Fuels

100 90 80 70 60 50 40 30 20 10 0

NaOH=0.1% NaOH=0.2% NaOH=0.4% NaOH=0.6% NaOH=0.8% NaOH=1% 0

20

40

60 80 Time (min)

100

120

140

Figure 10


24

100 90 80 70 60 50 40 30 20 10 0

Na2CO3=0.1% Na2CO3=0.2% Na2CO3=0.4% Na2CO3=0.6% Na2CO3=0.8% Na2CO3=1% 0

20

40

60 80 Time (min)

100

120

140

Figure 11

30

30 Solubilization Ratio (cc/cc)

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

Hw/H(total)

Page 25 of 29

Vo/Vs Vw/Vs

25

25

20

20

15

15

10

10

5

5 0

0 0

1

2


7

8

9

Figure 12


25

Energy & Fuels


30

30 Vo/Vs Vw/Vs

25

25

20

20

15

15

10

10

5

5

0

0 0

1

2


7

8

9

Figure 13

30

30 Solubilization Ratio (cc/cc)

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 26 of 29

Vo/Vs Vw/Vs

25

25

20

20

15

15

10

10

5

5 0

0 0

1

2


7

8

9

Figure 14


26

Page 27 of 29

30


30 Vo/Vs Vw/Vs

25

25

20

20

15

15

10

10

5

5 0

0 0

1

2


7

8

9

Figure 15

3 2.8 2.6 2.4 2.2 2 1.8 1.6 1.4 1.2 1 0.8 0.6 0.4 0.2 0

14 12 10 IFT-0.2 wt% SURF1 IFT-0.1 wt% SURF1 IFT-1 wt% SURF1 PH-0.2 wt% SURF1 PH-0.1 wt% SURF1 PH-1 wt% SURF1 0

50000

100000

150000 200000 Salinity (ppm)

250000

8 6

PH

IFT (mN/m)

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

4 2

0 300000

Figure 16


27

Page 28 of 29

3 2.8 2.6 2.4 2.2 2 1.8 1.6 1.4 1.2 1 0.8 0.6 0.4 0.2 0

14 12

IFT-NaOH IFT-Na2CO3 IFT-NaBO2 IFT-TEA PH-NaOH PH-Na2CO3 PH-NaBO2 PH-TEA 0.5

1 Alkaline Concentration (wt%)

8 6

PH

10

0

4 2 0

1.5

Figure 17

3 2.8 2.6 2.4 2.2 2 1.8 1.6 1.4 1.2 1 0.8 0.6 0.4 0.2 0

14 12 IFT-NaOH IFT-Na2CO3 IFT-NaBO2 IFT-TEA PH-NaOH PH-Na2CO3 PH-NaBO2 PH-TEA

10 8 6

PH

IFT (mN/m)

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

IFT (mN/m)

Energy & Fuels

4 2 0

0

30000

60000

90000 120000 Salinity (ppm)

150000

180000

Figure 18


28

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Energy & Fuels

(a)

(b)

(c)

(d) Figure 19


Evaluation of Chemicals Interaction with Heavy Crude Oil through

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