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Role of Acid Components and Asphaltenes in Wyoming Water-in-Crude Oil Emulsions V. Alvarado,* X. Wang, and M. Moradi Department of Chemical and Petroleum Engineering, University of Wyoming, Department 3295, 1000 East University Avenue, Laramie, Wyoming 82071, United States ABSTRACT: Two classes of stabilizing oil components in water-in-crude oil emulsions for three oils from the state of Wyoming are investigated in this paper. The associated contributions appear to be different for each crude oil. Given the molecular complexity of crude oils and their properties, more than one oil component is thought to contribute to emulsion stability and we speculate that stability is the outcome of competing materials adsorption on water oil interfaces, in addition to interfacial and bulk rheology. The presence of emulsion-stabilizing acids and their complexes, presumed here to be naphthenic acids for at least one of the crude oils used here, is claimed to stabilize water-in-crude oil emulsions. The presence of acids is inferred from pH changes of the resolved water fraction obtained in centrifuge-bottle tests, as well as in partition tests. The oil wash test, in which oil obtained after emulsification is reused to generate new water-in-crude oil emulsions, is used here to elucidate the role of the water-insoluble fraction. The effect of di- and monovalent cations in solution on emulsion stability is compared for two oils. Results show that stability improves when the aqueous phase contains calcium ions only in contrast with solutions containing sodium ions exclusively at the same ionic strength.
’ INTRODUCTION Emulsion-stability-controlling mechanisms can be linked to two coalescence-suppressing interfacial barriers, namely, hindered film drainage and interfacial resistance to rupture.1 Film drainage depends upon the rheology of the continuous oil phase for water-in-crude oil emulsions and, thus, temperature, among other factors.1,2 The interfacial coating film controls emulsion stability once droplets flocculate by suppression of unstable dimples, which we denominate interfacial resistance to rupture. We are interested in knowing how materials naturally existing in the oil act as effective stabilizers. We hypothesize that the dominant natural stabilizers are organic acids3 5 and asphaltenes,6 8 as several authors do. Czarnecki and Moran9 indicate that asphaltic material from the oil adsorbs slowly and irreversibly and forms rigid skins of water-in-oil emulsions in competition with surfactant-like species. Naphthenic acids (NAs) can form neutralization products (naphthenates) with cations in the aqueous phase. These complexes can stabilize emulsions because of their amphiphilic characteristics,10 12 but can also act in conjunction with other oil components. Brandal et al.1,2 investigated the interactions between dissociated NAs and divalent metal cations across model oil alkaline water interfaces by tracking changes in dynamic interfacial tension (IFT). Their results show that the dynamic IFT strongly depends upon the NA structure, type of divalent cation in aqueous solution, and concentration of the compounds, as well as the pH of the aqueous phase. The divalent cations in the aqueous phase can react with saturated NAs and cause a permanent drop in the IFT because of the formation of positively charged monoacid complexes, which possess high interfacial activity. This implies that the presence of dissociated acids can affect emulsion stability. r 2011 American Chemical Society
Strassner13 points out that the rigid interfacial films formed by asphaltenes are the strongest at acidic pH, intermediate in strength at neutral pH, and become very weak or are converted to mobile films at basic pH. Omole and Falode14 also observe that the reduction in pH is likely to induce the precipitation of sludge and that a rigid interfacial film formed by the presence of asphaltenes is the strongest at acidic pH. Varadaraj et al.15,16 hypothesize that asphaltenes and NAs interact synergistically, leading to acid base complexes, which exhibit surfactant-like properties, aggregate at the oil water interface, and reduce the oil water IFT. These mechanisms may also contribute to the formation of stable emulsions. Our experimental results show that brine containing a divalent cation is conducive to stronger emulsions compared to an aqueous phase containing monovalent cations only, at the same ionic strength.1,17 The reason could relate to the formation of complexes between divalent cations with dissociated NA and/or asphaltenes, which changes the interfacial properties of water and oil interfaces and inhibits droplets coalescence.12 Langevin et al.18 point out that resins solubilize asphaltenes in oil; therefore, their removal lowers emulsion stability. Yang et al.19 studied the dynamics of asphaltene and resin exchange at the oil/water interface and hypothesized that resin-solvated asphaltenic aggregates are able to diffuse and adsorb to the oil water interface more quickly than larger pure asphaltenic aggregates, improving interfacial rigidity. However, when resins become the primary adsorbent, they displace asphaltenes, reducing emulsion stability.19 The reason why resins displace asphaltene from the interface is because they are more surfactant-like Received: July 22, 2011 Revised: September 5, 2011 Published: September 08, 2011 4606
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Table 1. Crude Oil Properties crude oil name
a
viscosity at
density at
22 °C (cP)
22 °C (g/mL)
HACa (%)
TANb
TBNc
TAN/HAC
(mg of KOH/g)
(mg of KOH/g)
(mg of KOH/g)
Raven Creek (RC)
18
0.8652
1.3
0.090
0.904
0.07
Tensleep (TS)
19
0.8692
3.2
0.16
0.96
0.05
Gibbs Field (GF)
43.5
0.9099
9
0.121
3.195
0.013
HAC = hexane asphaltene content (%). b TAN = total acid number. c TBN = total base number.
than asphaltenes and thermodynamics favors adsorption on the interface, minimizing surface free energy. Macroemulsion stability is a term used to refer to relative stability among emulsions and not an absolute determination, because by definition, these are not thermodynamically stable systems. Instead, proxies are used for comparison purposes. Stability proxies are protocols designed and tested to reflect the relative stability of water-in-oil emulsions.2 Typically, one is interested in relative changes in the measured quantity that serves as a proxy. The most commonly used proxy is the amount of water resolved in bottle tests.20,21 Although there is no standard for stability determination in bottle tests, the volume of water obtained from phase separation can be used as a proxy.21 A significant number of other proxies are based on the time evolution of the droplet size distribution.2,22 These proxies do not rely on measurements resulting from the phase-separation step (i.e., water resolution), but instead, they reflect the coalescence process that leads to the release of interfacial energy. One method that also provides interfacial process information is electrorheology.1,17,23 In this method, the emulsion is placed between plates in a parallel-plate configuration (or in the gap in Couette or concentric cylindrical geometry). An electric field is applied by polarizing parallel plates, and a dynamic shear is applied in the linear viscoelastic regime. As the field is increased after reaching a steady state, the viscosity of the water-in-oil emulsion grows as the result of water droplets chaining up together. If the electric current is measured at a given value of the electric field, the current will increase significantly and the viscosity will generally drop. This value of the field above which irreversible changes in the emulsion structure occur is denominated the critical electric field (CEF), which can be used as a proxy of stability. In this work, we apply an experimental protocol, i.e., wash test, to determine how emulsion stability changes as oil is reused in consecutive wash tests. A similar “washing” experiment was performed by Xu et al.24 They found that only a small fraction of the total asphaltenes is involved in the formation of dropletcoating skin. In our view, this reflects the difficulty of interpreting the effect of a solubility class. Xu et al.24 generated a series of water-in-oil emulsions using increasing amounts of water blended into diluted bitumen. Xu et al.24 concluded that emulsion stability decreased in successive washes. The objective of the present work is to investigate the impact of water-soluble and insoluble fractions with regard to increased stability as the aqueous-phase ionic strength decreases. We experimentally probe the oil water system through tests where soluble species, presumably associated with the dissolution of organic acids in the crude oil into a aqueous phase, are depleted in partition tests. The wash test should predominantly reflect the impact of waterinsoluble species, likely a fraction of the asphaltene solubility class in the crude oil. The impact of these two tests is evaluated through changes in emulsion stability responses.
Table 2. Salt Weight Fractions Used To Prepare Saline Solutions species
concentration (ppm)
NaCl
29803
CaCl2
2104
Na2SO4 MgSO4
5903 841
total dissolved solids (TDS)
38651
Figure 1. Setup for the partition test between oil and brine.
’ MATERIALS AND METHODS Three crude oils from the state of Wyoming are used to prepare waterin-crude oil emulsions. The oils vary in density from light oil with low asphaltene content [Raven Creek (RC)], to intermediate density and significant asphaltene fraction [Tensleep (TS)], to heavy oil containing the highest asphaltene content among the three [Gibbs Field (GF)]. Their basic properties are shown in Table 1. NaCl and CaCl2 aqueous solutions, having the same ionic strength, 0.6724 M, are prepared by dissolving analytical-grade salts in predetermined weight fractions. This ionic strength was selected to be the same as that of a synthetic reservoir water previously used in our research, which represents a partial makeup of a Wyoming reservoir water, i.e., Minelusa brine (MLB). If a given aqueous solution is at 0.6724 M ionic strength, it is labeled 100% salinity. Several aqueous solutions are prepared by diluting the initial solution by the addition of distilled water to obtain aqueous phases at 10 and 1% of the original salinity. The salt weight fractions used to prepare the base solution are shown in Table 2. Emulsion Preparation. Emulsions are prepared by homogenizing the fluids in the Ultra Turrax T25 basic (IKA-Werke) at 6500 revolutions per minute (rpm) for 3 min at the desired water/oil ratio at ambient temperature. Partition Test. An oil/water volume ratio of 1:1 at ambient temperature is used for partition tests; brine pH is measured using a two-end opened tube anchored in the water phase. In this test, water is 4607
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added to a beaker first and then oil is carefully poured to avoid mixing with water, while the glass tube is kept immersed in the brine (as sketched in Figure 1). A magnetic stirrer is placed at the bottom of the beaker to accelerate mass transfer from the oil to the aqueous phase. The stirring speed is kept low enough to avoid in situ emulsion formation. In some instances, this experiment is operated in a glovebox inflated with nitrogen, to limit CO2 exchange with the atmosphere. By doing this, we assume that the brine pH change is primarily the result of mass transfer of acid components from the oil to the aqueous phase. Oil Wash Test. This test is designed to study emulsion stability alteration by reusing the same oil used to prepare the initial water-in-oil emulsions. The procedure followed for RC and TS crude oils is the same but differs for GF oil, given the different stability responses, as determined in previous stability analyses (protocols are sketched in Figure 2). For the lighter oils, RC and TS, emulsion stability is determined using the centrifuged-bottle test. At the end of each wash, the resolved water volume was carefully drawn to measure pH. For GF, the centrifuge force needed to break the emulsions is not attainable under our current experimental conditions; therefore, electrorheology is used to determine emulsion stability after each wash by measuring the CEF.13 Asphaltene Determination. Crude oil samples are first filtered to separate asphaltene aggregates and other suspensions already present in the crude oil, produced after the centrifugation step by possible rupture and detachment of interfacial skins and accumulation of this type of material. The original crude oil samples are filtered using either a 2.5 μm filter for RC and TS and/or a 11 μm filter for GF oil. The use of different filters responds to the viscosity differences among oils. Then, 1 g of oil and 40 mL of analytical-grade n-hexane are combined in a glass flask. The flask is sealed with a stopper and placed on the stirrer plate, and the mixture is stirred for 16 h at ambient conditions. After aging for 16 h, a funnel filter assembly is used to separate precipitated asphaltenes from the oil/precipitant mixture. Polytetrafluoroethylene (PTFE) membrane filters with the pore size of 0.2 μm are used to separate the asphaltene. Filters are preweighed and placed in the funnel filter assembly. The oil/ hexane mixture is then poured into the funnel cup, and the assembly is connected to the vacuum pump to initiate filtration. During filtration, the funnel cup is rinsed with several aliquots of n-hexane, usually 100 mL, to prevent deposition of asphaltene on the cup wall and also to wash the deposited layer. Rinsing is continued until a clear filtrate is obtained. After the final rinse, suction with the vacuum line is continued until the deposited asphaltene dries up enough to form cracks. After drying the samples, the filter is peeled off and weighed. The funnel cup is rinsed with toluene to dissolve the asphaltene stuck to the cup into the preweighted container and left to completely dry prior to weighing. The weight difference between the membrane filter and container before
and after asphaltene deposition are added to calculate the asphaltene content of the sample. The asphaltene content is reported as grams of asphaltene per 1 g of oil, i.e., as a weight fraction. The values reported for the TS second wash are the average of the values measured for the two samples from the second wash test, in view of the limited volumes available. Emulsion Stability Determination. Bottle tests with the use of a centrifuge and electrorheology are the methods used for stability determination in this work. In the bottle test, a sample of the emulsion is placed in a vial and the emulsion is accelerated in a centrifuge to accelerate phase separation. The water volume resolved is measured as a function of time. Typically, the onset of phase separation can be used as a proxy of emulsion stability, but we choose to measure the water volume resolved at the time phase separation slows (determined when the water volume plateaus). Bottle tests are impractical or unusable for very stiff emulsions, in which case electrorheology is used as a proxy. In this test,1,17 the emulsion placed between parallel plates is subject to a progressively larger electric field (voltage drop/gap) until the electric current goes through an inflection point (at first, the current rapidly increases with the electric field and then this growth slows) and the emulsion viscosity drops. Consistency is attained by comparing the determination via viscosity changes and current behavior. Repeated rheograms below and above the CEF value typically reflect the breakdown of the emulsion structure.17
’ RESULTS AND DISCUSSION Partition Test. Partition Test of RC with NaCl Brine at Four Salinities. Partition tests for RC and NaCl brine at 100, 20, 10,
and 1% salinity for a 1:1 ratio were performed to track the brine
Figure 3. pH change curve from the RC partition test with NaCl brine at four salinities.
Figure 2. Wash test protocol for (top) RC and TS and (bottom) GF oils. 4608
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Figure 4. pH change curve from the TS partition test with 1% NaCl brine.
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Figure 6. pH change curve from the GF partition test with 1% NaCl brine.
Table 3. Electrorheology Test Results of GF and 1% NaCl Brine Emulsions with and without the Partition Test sample name
Figure 5. Bottle test results of TS and 1% NaCl brine emulsion with and without the partition test.
pH change as a function of time, as shown in Figure 3. The results show that the lower the salinity, the lower pH value. Partition Test of TS with 1% NaCl Brine. Figure 4 shows partition test results for TS and 1% NaCl brine. The pH was tracked for 8 days until its value flattened out at approximately 4.41. To determine the impact of contacting oil and brine and, hence, oil and brine composition after partitioning on emulsion stability, four emulsions at an oil/water ratio of 3:1 (19.5 mL of oil and 6.5 mL of brine) were prepared using combinations of the original TS oil and 1% NaCl brine, as well as with the oil and brine recovered from the 1:1 partition test. TSp stands for TS oil after partitioning, and a similar convention is followed for 1% NaClp. Centrifuge speeds of 1000, 2000, and 3000 rpm were continuously used for 1 h each, but no water was resolved; therefore, the samples were finally centrifuged at 6000 rpm [7750 relative centrifugal force (rcf)] for 3 h, and the resolved water volume was carefully drawn with a pipet to determine the pH change. The bottle test pH and resolved water volume curves are shown in Figure 5. From the results, it can be concluded that the emulsion made with TS oil after the partition test (TSp) and the original 1% NaCl solution is the least stable, while the emulsion made with the original TS oil and 1% NaCl after the partition test is the most stable. The amount of water resolved of the other two samples turns out to be between the other two emulsions. More interestingly, the pH also follows a trend, in which the most stable emulsion corresponds to the lowest aqueous-phase pH
CEF (kV/m)
2:1 GF/1% NaCl
130
2:1 GF/1% NaClp
165
2:1 GFp/1% NaCl
230
2:1 GFp/1% NaClp
185
and the least stable emulsion exhibits the highest brine pH among these four samples. The aforementioned results directly show that the stability of TS emulsions reduces as crude oil loses some of its acid components and the acid partitioned into brine can help to form more stable emulsions. For TS oil, organic acids appear to have a dominant role in stabilizing water-in-oil emulsions. However, our results do not imply the lack of participation of other oil fractions. Partition Test of GF with 1% NaCl Brine. Unlike RC and TS crude oils, the test for GF partitioning with 1% NaCl brine did not show significant changes in pH after tracking it for 5 days (Figure 6). The pH range between 7.5 and 8 indicates that either little acid component transferred into brine or the dissociated acid is neutralized by base components in the crude oil. GF oil has a comparatively high total base number (TBN) of 3.195 mg of KOH/g. The emulsion stability using the partitioned oil and brine are also compared for four samples at an oil/water ratio of 2:1 (20 mL of oil and 10 mL of brine). GFp and NaClp have the same meanings as those for TS crude oil. The stability was determined by electrorheology after the samples were centrifuged at 2000 rpm (2500 rcf) for 3 h. As Table 3 shows, the CEF values range from 130 to 230 kV/m, and no apparent trend can be inferred from these results. The current response with changing voltage is shown in Figure 7. Thus, we deduce that the stability of GF emulsions possibly depends more upon asphaltene than acid components. Partition Test of NA. To better understand the acid fraction partitioning between crude oil and brine, NA (Aldrich, acid number ∼ 230) was used in partitioning experiments mimicking the crude oil brine conditions to investigate NA behavior in aqueous phase at different compositions. To examine the partitioning, pH and total organic carbon (TOC) were measured. Panels a d of Figure 8 show the pH as a function of time for NaCl and CaCl2 at three dilutions. The results show that the NAs can partition to aqueous phase at a fairly fast rate. The final pH of 4609
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Energy & Fuels the solutions does not vary much when either 0.1 or 0.8 g of NA is added to the aqueous phase. In fact, a significant fraction of the added acid remains at the top of the solution throughout the experiment. This shows that NA is not very soluble in brine, a known fact. Brines prepared using either NaCl or CaCl2 do not exhibit distinct differences on pH response in this test. The result for TOC did not show any discernible trend with salinity either. However, the TOC values for CaCl2 brines were consistently lower, typically in the range of 140 200 ppm, in contrast with results for NaCl, for which TOC ranged from 200 to 220 ppm. As observed in the past,4,5 calcium tends to form stronger more solid-like naphthenate complexes than sodium. If soluble species are dominated by acids dissociated in solution, the TOC trend could be explained by either of two hypotheses or a combination of the two. The first hypothesis points to a possible higher
Figure 7. Electrorheology results of GF and 1% NaCl brine emulsions with and without partitioning.
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solubility of the acids in NaCl brine. The second hypothesis is the formation of more stable calcium naphthenate complexes that tend to reside at the interface irreversibly. The second hypothesis is consistent with the higher stability of the emulsions in the presence of calcium. However, the Ca2+ and Na+ concentration measurements performed are inconclusive in this regard. Oil Wash Test. Oil Wash Test of RC. Four emulsions were prepared using RC oil and MLB at 100, 10, and 1% of the initial salinity by dilution with distilled water, at an oil/water ratio of 2:1 (25 mL of oil and 12.5 mL of brine). The emulsions were centrifuged, and the oil at the top of the sample was carefully drawn and then emulsified with 10 mL of brine for the next wash test at a fixed 2:1 ratio. The bottle test results were recorded by reading the volume of water resolved at 3, 10, and 30 min after centrifugation, and pH was measured at the end of the test by transferring the resolved water volume to a scaled tube using a
Figure 9. pH of brine change from the RC oil wash test.
Figure 8. pH change curve from NA partition test with brines: (a and b) 0.8 g of NA in 20 mL of NaCl and CaCl2 at different salinities and (c and d) 0.1 g of NA in 20 mL of NaCl and CaCl2 at different salinities. 4610
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Figure 10. Current voltage response of a 2:1 oil/water ratio at 25 °C and a frequency of 21 rad/s for the GF oil wash test with 1% NaCl brine.
pipet. The centrifuge force applied was strong enough to resolve most of the emulsified water for all of the salinities after centrifugation at 6000 rpm for 30 min. In this sense, the bottle test results did not provide a distinctive difference in the volume of resolved water among samples from different wash cycles and also different brine salinities. This means that no conclusion on the emulsion stability can be drawn at this rate of centrifugation. As in Figure 9, a lower aqueous solution pH was found at lower brine salinity. Also, it was observed that pH increased as the cycle of wash test increased, possibly because the acid components from the oil continue to deplete by partitioning into the brine. A possible consequence of resolving most of the water is that the interface-active fraction remains behind in the crude oil. Oil Wash Test of TS. For TS oil, the procedure was similar to that followed for the RC oil wash test. Two identical bottles of TS and 1% NaCl brine at a 3:1 oil/water ratio were prepared by homogenizing at 6500 rpm for 3 min to provide sufficient top oil volume for the next wash cycle, and then the vials containing the emulsion were centrifuged at 2000 rpm for 3 h, yielding 2 mL of water resolved from each bottle with a pH value of 3.77. A 20 mL oil volume from the top of each bottle was obtained and emulsified with 1% NaCl brine again at a 3:1 ratio. In the second wash, a 5 mL water volume was resolved, yielding an increased pH value of 5.23. This experiment for TS showed that the stability of emulsion decreased and the pH of brine increased after each wash was completed. It is appropriate to conclude that stability was impacted by depletion of acid components from the oil. Oil Wash Test of GF. For GF oil, which is heavier and has a considerably higher asphaltene content than the other two oils tested, the procedure included a different stability determination method (sketched in Figure 2). A 2:1 oil/water ratio was selected, and emulsions were prepared with GF and 1% NaCl under the same conditions as for RC and TS. Because there was much more loss of oil because of the fact that emulsions were generally more stable for this oil, the first run was made up in three bottles to provide sufficient oil for the next run. After centrifugation of the emulsions at a moderate acceleration (2000 rpm for 3 h), the top oil fraction was obtained and emulsified with the same brine at a 2:1 ratio, which was enough to prepare two bottles of the same emulsion. This procedure was followed 3 times until the amount of top oil separated from the previous test was insufficient for the next run. The emulsions from each wash were used for electrorheology to determine their stability. The electrorheological (ER) results showed a decreased
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Figure 11. Current voltage response of a 3:1 oil/water ratio at 5 °C and a frequency of 21 rad/s for TS oil with NaCl and CaCl2 brine at three salinity values.
Figure 12. Current voltage response of a 2:1 oil/water ratio at 25 °C and a frequency of 21 rad/s for GF oil with 1% NaCl and 1% CaCl2.
CEF value of 180, 125, and 85 kV/m for tests 1, 2, and 3, respectively, corresponding to a decreased water-in-oil emulsion stability (Figure 10). The crude oil refractive index (RI) was also measured with the purpose of tracking changes in the top oil, because we assumed that the oil was being depleted of a polar component, such as asphaltene. However, the RI data did not show any recognizable trend. The change in RI was within the intrinsic equipment error (not shown here). Divalent Cation Effect on Emulsion Stability. TS Crude Oil. The effect of the presence of divalent cations was tested for TS oil by comparing stability results for NaCl and CaCl2 solutions at three salinities. An oil/water ratio of 3:1 (22.5 mL of oil and 7.5 mL of brine) was selected by screening from previous work.1 Samples were centrifuged at 1000 rpm (1250 rcf) for 3 h, and no water was resolved for any of the samples. The amount of top oil for these six samples was roughly 17.5 mL, with water content in the emulsion of about 60%. The same water content is a condition for the ER method to produce comparable stability results among samples. A temperature of 5 °C was chosen because more distinct differences could be observed among samples at a lower temperature from comparatively higher CEF values. For all three salinities investigated, emulsions made with pure CaCl2 brine have about 15 kV/m or higher CEF than those made with pure NaCl brine of the same ionic strength (Figure 11). A lower salinity yielded a higher CEF value for both NaCl and CaCl2 brine. GF Crude Oil. GF oil emulsions with 1% NaCl and 1% CaCl2 brines were compared to see the effect of divalent cations on stability using the ER method. Emulsions made with pure CaCl2 4611
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Table 4. Asphaltene Content for TS Oil before and after the Wash Test TS original
TS first wash
TS second wash
(wt %)
(wt %)
(wt %)
3.3 3.4
3.2 3.6
3.8 2.9
3
3.7
3.4
3.4
average
3.5
3.4
3.4
sample 1 2
Table 5. Asphaltene Content for GF Oil before and after the Wash Test GF original
GF first wash
GF third wash
(wt %)
(wt %)
(wt %)
1
9.7
10.7
9.8
2
9.6
10.6
9.6
average
9.65
10.65
9.7
sample
brine exhibited roughly 40 kV/m higher CEF than those made with pure NaCl solutions with the same ionic strength, being 110 and 70 kV/m (Figure 12). Asphaltene Determination. Four samples for TS crude oil, including original oil, one sample from the first wash, and two samples from the second wash, and three samples for GF crude oil, including original oil and first and third washes, were analyzed. Table 4 summarizes our findings for TS oil. Three separate determinations of asphaltene content were completed. The second column in the table corresponds to analysis of the oil prior to any emulsion preparation. The first observation is the degree of variability in asphaltene content, which might correspond to experimental errors in our procedures (typically 6% of asphaltene weight percentage). However, given the modest asphaltene content and volumes analyzed, this error might originate in sample sample variations. No clear trend can be extracted for the TS oil. If a fraction of the asphaltenes in TS oil plays a role in stabilizing the emulsions, perhaps the percentage over the total oil cannot be determined with our current procedures. One possibility is that asphaltenes play a minor role in stabilizing TS emulsions. Table 5 shows the asphaltene content of the GF oil prior to oil washes and third and fourth columns of the first and third wash samples. Unfortunately, there was insufficient sample volume to analyze the second wash. The first significant observation is the higher value of the asphaltene content in the first wash sample. To understand differences in the observations, it is important to recall that the aggregation state of asphaltenes changes from the original crude oil to that of the oil obtained from wash tests. During emulsification, asphaltene aggregates at interfaces and resin molecules can be “trapped” along with asphaltene. Also, instead of nanoclusters of organic molecules, detached interfacial films become suspended in the free-oil phase at the microscale. These differences in fluid molecular structuring could produce a bias in the gravimetric method used to determine the asphaltene fraction, and in turn, the comparison between the original oil sample and that coming from the first wash appears inconsistent. However, the processes by which asphaltene samples are obtained in successive washes make this aspect of the comparison more consistent. As can be noticed in Table 5, the asphaltene
content drops from the first to the third wash. The entire sample volume from the second wash was used for the third wash; therefore, an insufficient aliquot was available for determination in the second wash. The significant decrease in asphaltene content is interpreted here as the depletion of asphaltene by the formation of viscoelastic films. Only a small fraction of the asphaltene is likely to participate in the formation of interfacial films. Xu et al.2 found this to be true in their system.
’ CONCLUSION For RC and TS oils, acid components appear to contribute significantly to stabilizing emulsions. On the other hand, for GF oil, pH measurements did not provide evidence of acid fractions dissolved in the aqueous phase. We speculate that asphaltene interfacial action/dynamics is possibly more active than organic acids with regards to stabilizing emulsions. Increased CEF values from emulsions made with brine containing calcium and not sodium show that divalent cations possibly form more active surface complexes with NA and/or asphaltenes for two of the oils tested. The phenomenon, i.e., a lower salinity of brine corresponding to a higher stability of emulsion for all of the crude oils tested, could be explained by differences in solubility of organic acid in brine at different salinity values. The results here clearly confirm that low-salinity conditions favor water-in-oil emulsion stabilization, but the crude oil component responsible for this stabilization is not unique. The results in this work point to more complex mechanisms, and several competing fractions of the crude oil are likely to contribute to produce stabilizing interfacial barriers. In this sense, oil water interfacial changes that prompt emulsion stability do not require one organic fraction of the oil only. Additional oil types should be investigated to determine how ubiquitous this phenomenon is. Our future research will use mass spectroscopy and high-field nuclear magnetic resonance (NMR) to understand molecular organization in solution, particularly on the asphaltic fractions of the oil. ’ AUTHOR INFORMATION Corresponding Author
*Telephone: +1-307-766-6464. Fax: +1-307-766-6777 . E-mail:
[email protected].
’ ACKNOWLEDGMENT This material is based on work supported by the University of Wyoming School of Energy Resources through its Graduate Assistantship program. We acknowledge the Enhanced Oil Recovery Institute at the University of Wyoming for financial assistance. ’ REFERENCES (1) Wang, W.; Brandvik, A.; Alvarado, V. Energy Fuels 2010, 24, 6359–6365. (2) Alvarado, V.; Wang, X.; Moradi, M. Energies 2011, 4, 1058–1086. (3) Langevin, D.; Poteau, S.; Henaul, I.; Argillier, J. F. Rev. Inst. Fr. Pet. 2004, 59, 511–521. (4) Mohammed, M. A.; Sorbie, K. S. Colloids Surf., A 2009, 349 1–18. (5) Mohammed, M. A.; Sorbie, K. S. Colloids Surf., A 2010, 369, 1–10. 4612
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