Review pubs.acs.org/EF
Asphaltene Solubility and Fluid Compatibility Irwin A. Wiehe* Soluble Solutions, 3 Louise Lane, Gladstone, New Jersey 07934, United States ABSTRACT: This is a review of petroleum asphaltene solubility as it relates to production and refining in terms of changes in temperature, pressure, and composition. While the current concept of asphaltenes and asphaltene solubility is changing rapidly in the scientific literature, giving the appearance of a field in chaos, evidence is presented that the many of the older approximations may still be adequate enough to solve practical asphaltene insolubility problems. Actually, solubility parameters and the regular Flory−Huggins model may describe petroleum phase behavior better than they do for any other system. The oil compatibility model for avoiding asphaltene insolubility during the processing of crude oils is discussed in detail. For production applications with live oils at reservoir conditions, the objective is to predict asphaltene solubility or insolubility from only measurements at ambient conditions and knowledge of the quantity and composition of the dissolved gas. Several groups have reported achieving this goal using either the regular Flory−Huggins model or the perturbed chain modification of the statistical associating fluid theory (PC-SAFT) equation of state.
■
INTRODUCTION This review of asphaltene solubility is being written when the field is in a state of disarray. While one previously thought that petroleum asphaltenes had large molecular weights, containing many large polynuclear aromatics, considerable evidence is pointing toward much lower molecular weights, containing only one large polynuclear aromatic.1 However, these asphaltenes are reported to form nanoaggregates that form larger clusters.2 While resins were credited for keeping asphaltenes dispersed in petroleum, evidence indicates there is no special attraction between resins and asphaltenes.3,4 Although it has been popular to describe asphaltene solubility quantitatively with regular solution theory and solubility parameters, direct measurements of dilute asphaltene mixtures indicate that regular solutions or any other simple solution thermodynamic concept do not apply.5 Finally, the experimental method of measuring the onset of asphaltene insolubility with precipitation has been criticized for not waiting many days or weeks for equilibrium to be established.6 This disarray of petroleum science makes the field somewhat chaotic but still exciting and fruitful for research and applications. Petroleum is so complex with a high degree of uncertainty that no concept is definite. It is easy to conclude that any concept does not describe the full complexity. However, this author is a pragmatic engineer that looks for simple approximations to petroleum that can be applied to improve petroleum technology and continues to be amazed how well these simple approximations work. This author also has a larger foot in the petroleum downstream than the upstream and naturally requires new concepts about petroleum to apply to both.
chemical structures that are characterized by their high aromaticity (∼50% aromatic carbons) and high molecular weight. In the face of recent evidence, this author7 still ascribes to the opinion that the average molecular weight of asphaltenes is of the order of 3000 and contains multiple islands of polynuclear aromatics of 4 aromatic rings or larger. In thermal treatment, many of these polynuclear aromatics can quickly grow by dehydrogenation, because on the order of 25% of the hydrogens in asphaltenes are on saturated rings, fused to an aromatic ring.7 In addition, thermal reactions tend to crack the more aliphatic pendant groups bonded to these aromatic and saturated rings. Both of these reactions make thermally converted asphaltenes more aromatic and less soluble. Thanks to the impressive, sophisticated methods of Mullins1 and others, today the more popular view of asphaltene chemical structure is that asphaltenes have an average molecular weight of the order of 700 with only one large polynuclear aromatic per molecule. However, at such a low molecular weight one should expect asphaltenes to evaporate in refinery Fluid Cokers and fluid catalytic crackers (FCC) at temperatures of 500 °C or higher under a high flow of steam. Actually, in these cases, only a very minor fraction of asphaltenes evaporates. As shown in Table 1, the evaporated asphaltenes from a fluid catalytic Table 1. Comparison of FCC and Resid Asphaltenes7 H/C
avg VPO MW
avg VPO MW
asphaltenes
(atomic)
(130 °C, o-DCB)
(50 °C, toluene)
FCC resid
0.820 1.15
679 2980
682 5600
a
Reproduced by permission of Taylor and Francis Group, LLC, a division of Informa plc.
■
ASPHALTENE CHEMICAL STRUCTURE Molecular Weight. Asphaltenes are defined here as the portion of petroleum that is soluble in toluene but insoluble in n-heptane, the least soluble portion of petroleum at temperatures above the melting point of wax (usually less than 60 °C). Asphaltenes are a mixture of approximately a million different © 2012 American Chemical Society
a
Special Issue: Upstream Engineering and Flow Assurance (UEFA) Received: February 15, 2012 Revised: June 8, 2012 Published: June 11, 2012 4004
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
cracker has VPO (vapor pressure osmometry) molecular weights of the order of 700 with one large polynuclear aromatic per molecule (not high enough molecular weight to include more than one large polynuclear aromatic) and with an H/C atomic ratio of about 0.8 as compared with 1.15 for the average asphaltene from a vacuum resid. While typical asphaltenes associate, the evaporated asphaltenes do not associate (molecular weights measured by vapor pressure osmometry are the same in a poor solvent, toluene, and in a good solvent, o-dichlorbenzene). Since the usual criticism of VPO is that it measures the associated molecular weight of asphaltenes, this is clearly not the case for these evaporated asphaltenes. Hence, if the very minor fraction of evaporated asphaltenes has a molecular weight of close to 700, then one would expect the vast majority of asphaltenes, those that do not evaporate, to have molecular weights much greater than 700. As a result, one gets the impression that methods that measure average molecular weights of asphaltenes to be 700 are only measuring the low molecular weight tail that are volatile (required for mass spectrometry) and are mobile (required for fluorescence emission and nuclear magnetic resonance). It has just been concluded that evaporated asphaltenes with one large polynuclear aromatic per molecule do not associate. On the other hand, the overwhelming majority of asphaltenes associate and are large enough in molecular weight to accommodate multiple large polynuclear aromatics. This suggests that multiple large polynuclear aromatics in an asphaltene molecule might be required to provide the mechanism for association. Average Asphaltene Molecule. Asphaltenes also have the highest concentration of sulfur (∼7 wt %), oxygen (∼1.5 wt %), nitrogen (∼1.1 wt %), vanadium (∼700 ppm), and nickel (∼200 ppm) of all the fractions in petroleum.7 The approximate chemical formula for an average 3000 molecular weight asphaltene is
Figure 1. Two-dimensional solubility parameter diagram for the asphaltenes fraction of Cold Lake vacuum resid at a concentration of 0.1 g/25 mL. From “Two-Dimensional Solubility Parameter Mapping of Heavy Oils” by Irwin A. Wiehe, Fuel Science and Technology International Volume 14, Issue 1−2 (1996), pp. 289−312, reprinted by permission of Taylor & Francis.
C205H 236S7 O3N2
with the average asphaltene molecule not containing any vanadium or nickel. Although sulfur is not substantially more electronegative than carbon, hydrogen bonding involving elecrtronegative oxygen atoms and/or nitrogen atoms has been erroneously credited for causing asphaltene association, as will be described in the next section.
■
ASPHALTENE PHYSICAL INTERACTIONS Solubility in Liquids. This author determines physical interactions of materials by which liquids dissolve or do not dissolve the material on a plot of complexing solubility parameter component versus field force solubility parameter component.8 An example is shown in Figure 1 for the asphaltene fraction of Cold Lake vacuum resid. Each point in this figure represents a particular liquid, and the polygon area encloses the group of liquids that are solvents. Carbon disulfide, which has no ability to form complexes but has a high field force solubility parameter, dissolves these asphaltenes. This indicates that the strongest interactions between asphaltenes are strong van der Waal’s interactions, probably between polynuclear aromatics and not hydrogen bonding. As a result, the solubility of asphaltenes in petroleum can be described by only the overall solubility parameter. By comparison, Figure 2 is a two-dimensional solubility parameter diagram for a gas oil fraction formed from Wyodak coal by the Exxon Donor Solvent process that contains 3.3 wt % oxygen and has a molecular
Figure 2. Two-dimensional solubility parameter diagram for the gas oil fraction (343−538 °C) formed from Wyodak coal by the Exxon Donor Solvent process at a concentration of 0.1 g/25 ml. From “TwoDimensional Solubility Parameter Mapping of Heavy Oils” by Irwin A. Wiehe, Fuel Science and Technology International Volume 14, Issue 1−2 (1996), pp. 289−312, reprinted by permission of Taylor & Francis. 4005
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
weight of 385.8 This gas oil is only soluble in liquids of moderate to high complexing solubility parameter component because its strongest interaction is hydrogen bonding, and as a result, it needs two solubility parameter components to describe its solubility. X-ray Diffraction. Another method to probe the interactions of petroleum fractions is by X-ray diffraction. Figure 3 shows the X-ray intensity as a function of twice the
Figure 4. Physical model of petroleum. Copyright 1998 from Process Chemistry of Petroleum Macromolecules by Irwin A. Wiehe. Reproduced by permission of Taylor and Francis Group, LLC, a division of Informa plc.
dispersants can associate with the asphaltene particle but not with other resins. These resins associated with the asphaltene particle are in dynamic equilibrium with unassociated resins. Meanwhile, the aromatics act as an asphaltene solvent to keep the asphaltene particles in solution, while the saturates act as an asphaltene nonsolvent to encourage the asphaltene particles to combine, grow, and precipitate. Therefore, the asphaltenes are pictured to be suspended in a delicate balance in petroleum that can be upset by increasing saturates or by decreasing resins and/or aromatics. This concept of a dynamic equilibrium between the polynuclear aromatics in asphaltenes with the polynuclear aromatics in resins is supported by the recent molecular thermodynamic theory of Rogel11 and the DC conductivity experiments of Sedghi and Goual.12 What about the recent proof that there is no special interaction between resins and asphaltenes? Somehow, some authors expected resins to be bound to asphaltenes, rather than interacting in dynamic equilibrium. One study3 used ceramic membranes to filter preferentially asphaltenes out of Athabasca bitumen and Maya crude oil. Unfortunately, these authors defined asphaltenes as n-pentane insoluble, rather than nheptane insoluble. Thus, they included a significant fraction of what the present author calls resins in their asphaltene fraction. Thus, it is not surprising that the smaller, pentane-soluble resins preferentially passed through the ceramic membranes. Nevertheless, they could not accurately determine the resin content of the material retained on the filter. Despite this, they conclude that there is no special retention of resins, aromatics, and saturates, as these fractions in the permeates remain the same on an asphaltene-free basis. Would not one expect smaller size resins to pass through the filter preferentially to the asphaltenes if they interact in dynamic equilibrium? Therefore, this paper
Figure 3. X-ray diffraction data of intensity versus twice the scattering angle for fractions of Arabian Heavy vacuum resid: asphaltenes, resins and saturates plus aromatics. Reprinted from Fluid Phase Equilibria, Vol 117 Issue 1−2, I. A. Wiehe and K. S. Liang, “Asphaltenes, resins, and other petroleum macromolecules”, pp. 201−210, Copyright 1996, with permission from Elsevier.
scattering angle for the asphaltene, resins, and saturates plus aromatics fractions of Arabian Heavy vacuum resid.9 All three fractions have broad peaks representing the interactions between paraffins. Only the asphaltenes have a peak representing the interactions between polynuclear aromatics. Location of the aromatic peak indicates that the distance between aromatics is about 3.55 Å. The greatest difference among fractions is at low scattering angle where the asphaltene fraction has a very large peak representing the distance between the centers of asphaltene particles of 3.9 nm (39 Å). Because one expects these particles to be closely packed in solid asphaltenes, this is the approximate size of asphaltene particles. Although X-ray diffraction of the resin fraction shows a shoulder at low scattering angle, this is likely to be caused by a small amount of asphaltenes in the resin fraction. Nevertheless, it is clear that the greatest difference between resins and asphaltenes is that asphaltenes associate through interaction of polynuclear aromatics to form particles while resins do not. Resin−Asphaltene Interaction. The author’s physical model of petroleum7 is shown in Figure 4, a modified version of Pfeiffer and Saal.10 The asphaltene particle, formed by the association of asphaltenes in the center, is in equilibrium with unassociated asphaltenes. The resins acting as natural 4006
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
disperse asphaltenes at much lower concentrations than natural resins.13 In addition, many crude oils, containing resins, are soluble in cyclohexane, while their asphaltene fraction, without resins, are insoluble in cyclohexane.8 Wang and Buckley14 did alkane flocculation measurements on crude oil, on toluene solutions of asphaltenes, and on toluene solutions of asphaltenes and resins. While they did not observe sharp changes in solubility as in Figure 5, they concluded that resins improve the solubility of asphaltenes more than could be accounted by solvent properties but found no evidence of specific interactions, like hydrogen bonding, between resins and asphaltenes. These conclusions are consistent with this author’s concept of a dynamic equilibrium between asphaltenes and resins through dispersion forces acting between large flat areas of polynuclear aromatics. This knowledge of the asphaltene dispersant quality of resins was used to solve a refinery fouling problem.15 This refinery hydrotreated an atmospheric resid using porous catalysts and found that, regularly, only near the end of each 1-year run, that the heat exchanger, which cooled the product, became severely fouled. This author reasoned that after the large pore catalysts partially filled with deposited nickel and vanadium, asphaltenes no longer could enter the pores but resins could, as shown in Figure 6. The data in Table 2 shows that at the beginning of the
certainly does not show conclusive proof about asphaltene− resin interactions. In the second study,4 asphaltene and resin gradients were measured in a petroleum reservoir in which asphaltenes separated and settled under gravitation. These authors concluded that only 8% of the resins are associated with the settled asphaltenes. Although the asphaltenes might separate because of a high concentration of saturates in the oil, it might also be promoted because there is not a strong interaction between resins and asphaltenes. What would be more interesting would be to determine the interaction of asphaltenes and resins in petroleum when the asphaltenes do not separate. Nevertheless, if anything, this evidence supports the physical model of petroleum in Figure 4, rather than contradicts it. The most direct evidence7 of the ability of resins to disperse asphaltenes is in Figure 5 and takes advantage of the toluene
Figure 5. Arab Light resins decrease the toluene equivalence of Arab Light asphaltenes (data: ●) up to a resin/asphaltene weight ratio of 4, the ratio in Arab Light Crude Oil (data: ▲). Copyright 1998 from Process Chemistry of Petroleum Macromolecules by Irwin A. Wiehe. Reproduced by permission of Taylor and Francis Group, LLC, a division of Informa plc.
equivalence test to measure the degree of insolubility of asphaltenes. In this test, 2 g of oil is mixed with 10 mL of a mixture of n-heptane and toluene. By trial and error, one determines the minimum percent toluene in the n-heptane− toluene mixture that is required to keep the asphaltenes in solution, and this is the toluene equivalence. The toluene equivalences of Arab Light asphaltenes and mixtures of Arab Light asphaltenes and resins were measured without the presence of saturates and aromatics. At a resin to asphaltene weight ratio of 0.4, the solubility improved greatly as compared to that with no resins. However, between a resin to asphaltene weight ratio of 1 and 4, there was only a small increase in asphaltene solubility. Yet, Arab Light crude oil has a resin to asphaltene weight ratio of 4, with less soluble asphaltenes than with just resins and asphaltenes alone in the same weight ratio. Apparently, the combination of saturates and aromatics in Arab Light crude act as a poor solvent that needs to be overcome by requiring more toluene for solubility. The data in Figure 5 shows that resins are asphaltene dispersants and not just asphaltene solvents. If resins were only asphaltene solvents, increasing the resin to asphaltene ratio from 1 to 4 would greatly reduce the percent toluene needed to dissolve asphaltenes. Nevertheless, resins are not great asphaltene dispersants because so much is required to improve asphaltene solubility. Certainly, synthetic dispersants can be designed to
Figure 6. At end of hydrotreater run asphaltenes bypass the catalyst. From “Self-Incompatible Crude Oils and Converted Petroleum Resids” by Irwin A. Wiehe, Journal of Dispersion Science and Technology Volume 25 Issue 3 (2004), pp.The asphaltenes become less soluble (higher toluene equivalence) at end of run for resid hydrotreater as the resin to asphaltene ratio decreases. From “Self-Incompatible Crude Oils and Converted Petroleum Resids” by Irwin A. Wiehe, Journal of Dispersion Science and Technology Volume 25 Issue 3 (2004), pp. 333-339, reprinted by permission of Taylor & Francis.
run asphaltenes were being hydrogenated and converted, while at the end of run the asphaltenes were only slightly thermally converted. Because the asphaltene concentration and hydrogen to carbon atomic ratio was nearly the same at the end of run Table 2. Properties of Feed and Product Asphaltenes at the Start and End of Hydrotreater Run15
start of run end of run
4007
asphaltene
yield, wt %
H/C, atomic
sulfur, wt %
feed product feed product
5.4 2.8 6.3 5.7
1.25 1.36 1.23 1.18
4.54 2.76 4.53 3.44
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
when the asphaltenes were insoluble as the asphaltenes in the feed where the asphaltenes were soluble, the insolubility of asphaltenes was not caused by the quantity or the quality of the asphaltenes. Meanwhile, the resins were being converted, and at the end of the run, the lower resin concentration relative to the asphaltenes caused the asphaltenes to precipitate upon cooling and foul the heat exchanger. To confirm, at the end of a run, the hydrotreater was operated at various conditions, while sampling the product and compared with the product of the beginning of the next run on fresh catalyst. The asphaltenes were only soluble (self-compatible) at end of run at the mildest hydrotreating conditions and at the beginning of the next run under more severe hydrotreating conditions. As is shown in Figure 7, once the resin to asphaltene ratio of the product of
Figure 8. Solvents and nonsolvents for Souedie crude oil at a concentration of 0.1 g/25 mL of liquid. Reprinted with permission from ref 16. Copyright 2000, American Chemical Society.
liquids. All the liquids that precipitated asphaltenes (nonsolvents) had the solubility parameter of methylcyclohexane or below, while all the liquids that kept the asphaltenes in solution (solvents) had the solubility parameter of cyclohexane or higher. Therefore, any oil, containing asphaltenes, has a flocculation solubility parameter such that if the solubility parameter of the medium is kept above this flocculation solubility parameter, the asphaltenes of this oil will be in solution. Since pure liquids only have discrete solubility parameters, flocculation solubility parameters will have to be determined by mixing solvents and nonsolvents. Also, since the solubility parameter of the oil contributes to the solubility parameter of the medium, the flocculation solubility parameter needs to be determined by extrapolation to infinite dilution in oil. However, by changing the oil concentration, a method is provided to determine also the solubility parameter of the oil. Compatibility Numbers. Because asphaltenes are defined as toluene soluble and n-heptane insoluble, all asphaltene containing oils will have flocculation solubility parameters between the solubility parameter of n-heptane and the solubility parameter of toluene. Therefore, this part of the solubility parameter scale of interest is stretched out, and the square root dimensions are eliminated by putting both the flocculation and oil solubility parameters on an n-heptane−toluene scale:
Figure 7. For the self-incompatible crude oil, Yme, the percent toluene in the test liquid at incipient asphaltene precipitation is independent of oil concentration. From “Self-Incompatible Crude Oils and Converted Petroleum Resids” by Irwin A. Wiehe, Journal of Dispersion Science and Technology Volume 25 Issue 3 (2004), pp. 333−339, reprinted by permission of Taylor & Francis.Copyright 2004, Taylor & Francis, Inc.
the hydrotreater dropped below 1.6, the asphaltenes became insoluble on cooling and the toluene equivalence increased with decreasing resin to asphaltene ratio. It is compelling how similar the shapes of the curves in Figures 5 and 7 are. In one case, Figure 5, the resin to asphaltene ratio is changed by mixing in different proportions, while in the other case, Figure 7, the same ratio is changed by reacting away the resins. Not only did this insight enable this refinery fouling problem to be solved but it further convinced this author that indeed resins disperse asphaltenes. Oil Compatibility Model.16,17 Asphaltene Solubility Criterion. As discussed previously, only the overall solubility parameter is needed to describe asphaltene solubility in petroleum. Likewise, if one restricts to liquids that only contain carbon, hydrogen, and sulfur, only their overall solubility parameter is required to characterize their solubility behavior. Then, 25 mL of each of these liquids was put in separate vials, and 0.1 g of Souedie crude oil was added to each and capped. After several weeks with frequent shaking, the Souedie asphaltenes were determined to be soluble or insoluble in each vial, using an optical microscope if necessary. In Figure 8, these results were plotted against the solubility parameter of the
⎡ δ − δH ⎤ Insolubility Number = IN = 100⎢ f ⎥ ⎣ δT − δH ⎦
(1)
⎡ δ − δH ⎤ Solubility Blending Number = SBN = 100⎢ oil ⎥ ⎣ δT − δH ⎦ (2)
where δf = flocculation solubility parameter, δoil = solubility parameter of the oil, δH = solubility parameter of n-heptane, and δT = solubility parameter of toluene. Volumetric Mixing Rule. Experimentally, one determines points of incipient asphaltene precipitation by mixing oil, toluene, and n-heptane. From the criterion of asphaltene insolubility, the solubility parameter of the mixture at each point of incipient asphaltene precipitation will be equal to the flocculation solubility parameter. In order to calculate the solubility parameter of mixing oil, toluene, and heptane, one 4008
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
minimum percent toluene required to keep asphaltenes in solution is determined, and this is the toluene equivalence, TE. The other test is the heptane dilution test, in which 5 mL of oil is titrated with n-heptane to determine the maximum volume, in milliliters, of n-heptane that can be added without precipitating asphaltenes, vH. The results of these two tests and the density of the oil in g/mL, d, are used to calculate the insolubility number, IN, and the solubility blending number, SBN.
uses the volumetric average, commonly done for solubility parameters. δf = δmix =
VTδ T + VHδ H + Voilδoil VT + VH + Voil
(3)
where VT = volume of toluene, VH = volume of n-heptane, and Voil = volume of oil. Cross multiplying and putting the flocculation solubility parameter in terms of the insolubility number and the solubility parameter of the oil in terms of the solubility blending number produces the following equation: ⎡ I − SBN ⎤ 100Voil 100VT = IN + ×⎢ N ⎥ VT + VH VT + VH ⎣ 100 ⎦
IN =
⎡ v ⎤ SBN = IN⎢1 + H ⎥ ⎣ 5⎦
(6)
Because about 20% of crude oils and many refinery process oils contain no asphaltenes, a method is required for measuring the solubility blending number of these oils. Of course, for an oil without asphaltenes, its insolubility number is set equal to zero. A reference oil containing asphaltenes with a measured toluene equivalence, TE, greater than 20 is selected. Two grams of the reference oil is mixed with 10 mL of the test oil without asphaltenes. If no asphaltenes precipitate, the toluene equivalence test is rerun on the reference oil except the test oil replaces toluene and the result is called the solvent oil equivalence, SOE. The solubility blending number, SBN, of the test oil is given by the following equation:
(4)
According to this equation, for points of incipient asphaltene precipitation, if we plot the percent toluene in the toluene−nheptane mixture versus 100 times the ratio of the volume of oil to the volume of the toluene−heptane mixture, the data will be on a straight line and the y-intercept will be the insolubility number. The x-intercept, HD, occurs when the volume of toluene is zero and enables determining the solubility blending number: ⎡ 100 ⎤ SBN = IN⎢1 + ⎥ HD ⎦ ⎣
TE vH ; 1 − 25d
(5)
SBN =
Data of incipient asphaltene precipitation for Arab Light crude oil in Figure 9 show that indeed the data falls on a line,
100TE SOE
(7)
If mixing reference oil with test oil precipitates asphaltenes, the toluene equivalence test is rerun on the reference oil except the test oil replaces n-heptane and the resulting percent toluene in the toluene−test oil mixture at the point of incipient asphaltene insolubility is called the nonsolvent oil equivalence, NSOE. The solubility blending number, SBN, of the test oil is given by the following equation: SBN =
100[TE − NSOE] 100 − NSOE
(8)
Commonly, the insolubility number and the solubility blending number of each prospective crude oil for a refinery are measured. If the refinery only blends crudes in which the solubility blending number of each crude is higher than the insolubility numbers of all the crudes in the blend, all the crudes are compatible in all proportions and no rapid organic fouling of the preheat exchangers or rapid organic coking of the distillation furnace tubes will result. If at least one crude in the blend has a solubility blending number less than at least one insolubility number of a crude in the blend, the blend is potentially incompatible. In this case, transposing the compatibility criterion of solubility parameters into compatibility numbers requires the volume average solubility blending number to be greater than the insolubility number of each crude in the blend. However, an Exxon patent18 covers the oil blending process of potentially incompatible oils using this criterion. In addition, slow organic fouling of heat exchangers and furnace tubes can result while using this criterion. This was discovered to be caused by compatible, but nearly incompatible, oils.19 Therefore, the criterion was broadened to require the volume average solubility blending number to be greater than 1.3 times the largest insolubility number of the oils in the blend and covered by another Exxon patent.20 The slow fouling by these compatible, but nearly incompatible, oils was attributed to asphaltenes adsorbing on surfaces but could also include cases
Figure 9. As predicted, a plot of percent toluene in the toluene− heptane mixture versus volume ratio of oil to toluene−heptane mixture for Arab Light crude oil falls on a line. Reprinted with permission from ref 16. Copyright 2000, American Chemical Society.
enabling the determination of the insolubility number and the solubility blending number from the intercepts. Moreover, this linear behavior has been obtained for a large number of asphaltene containing oils with no exception. Therefore, the concept of a single flocculation solubility parameter for each oil and the use of the volumetric average solubility parameter for the solubility parameter of a mixture are verified by this linear behavior. Oil Compatibility.7 Today, to minimize lab costs, only two points are measured to determine the insolubility number and the solubility blending number of an asphaltene containing oil. One of these is the toluene equivalence test. As described previously, in this test, a series vials are prepared containing two grams of oil and 10 mL of toluene−heptane mixture. By varying the percent toluene in the toluene-heptane mixture, the 4009
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
where the insolubility number is less than measured because of asphaltenes precipitating after the time scale of the laboratory tests. Nevertheless, in almost all cases that a blend is not potentially incompatible, it is also outside the region of nearly incompatible. Self-Incompatible Oils. Oils that contain insoluble asphaltenes are called self-incompatible.15 The number of crude oils that are self-incompatible used to be low but today the number is greater than 30 and rising quickly. An example is Yme crude oil from the North Sea, shown in Figure 10, with the
Figure 11. Schematic diagram of the Thermal Fouling/Coking Test Unit. Reprinted with permission from ref 19. Copyright 2001, American Chemical Society.
to study petroleum fouling. With the heater tube in the annulus controlled at 400 °C, a self-incompatible oil severely fouled the heater tube in only 30 min. Meanwhile, the unheated tube surrounding the heater tube remained completely clean. Pumping the oil at high velocity can reduce, but not eliminate, fouling by removing some foulant because of shear stress at the wall. Nevertheless, self-incompatible crude oils, when identified, should be avoided by refineries because of the increased cost of processing in terms of energy consumption and maintenance. Value of Oil Compatibility Model. The oil compatibility model and tests have proven to be a valuable tool that a refinery can use to purchase and schedule opportunity crudes while minimizing organic fouling. In addition, inorganic fouling caused by corrosion and desalter upsets need to be attacked in parallel. The oil compatibility model is especially valuable because of its simplicity that is based upon the concept that all points of asphaltene incipient precipitation of a given oil occur at the same solubility parameter of the medium. It is not really a thermodynamic model of chemical potential that requires solving simultaneous equations by equating chemical potentials of each component in each phase. Instead, once the insolubility number and solubility blending number of each crude is determined, one can immediately see which sets of crudes that are compatible in all proportions and which pairs of crudes should be avoided in any blend. While the oil compatibility model defines the operating window for avoiding insoluble asphaltenes, it cannot predict the quantity of asphaltenes precipitated outside this operating window, as can a thermodynamic model. Even this operating window defined by the oil compatibility model can be overly conservative. The laboratory detection of insoluble asphaltenes is done with an optical microscope after the mixture of oil, toluene, and nheptane is left to sit for 5 min at 60 °C. However, the oil is processed in the refinery at much higher temperatures and asphaltene solubility increases at higher temperatures in dead oils.7 In addition, the oil compatibility model neglects the ability of resins to disperse asphaltenes. As a result, mixing an oil having an excess of resins with an oil with a high insolubility number can lower this insolubility number. Consequently, some mixtures of oils predicted by the oil compatibility model to be incompatible are experimentally found to be compatible.7 Dynamic Asphaltene Aggregation. What are the effects of the slow rate of asphaltene precipitation on the oil compatibility tests and the predictions of the oil compatibility model? First,
Figure 10. For the self-incompatible crude oil, Yme, the percent toluene in the test liquid at incipient asphaltene precipitation is constant over oil concentrations measured. Reprinted with permission from ref 15. Copyright 2004, Taylor & Francis, Inc.
permission of Statoil and in which the term “test liquid” is the mixture of toluene and n-heptane at points of incipient asphaltene precipitation. If the oil contains insoluble asphaltenes, no n-heptane needs to be added to precipitate asphaltenes (vH = 0). At this condition, eq 6 shows that the solubility blending number equals the insolubility number, which equals the toluene equivalence. This not only includes the normal toluene equivalence at 2 g of oil and 10 mL of toluene plus n-heptane but at all higher ratios of oil to test liquid tested (0.25 to 0.63), as shown in Figure 10. Besides Yme, the only other self-incompatible crude oil that this author has permission to reveal is Isthmus, the second most produced crude oil in Mexico, because its identity as a selfincompatible crude oil has been published.21 However, selfincompatible crude oils can also be found in United States, Canada, Venezuela, and most other oil producing countries. In some cases, crudes are compatible at their source but become incompatible during transportation to the refinery. This commonly happens when a low solubility blending number crude is transported in the same pipeline or tanker as previously containing a high insolubility number crude and the asphaltenes are precipitated from the remaining oil in the pipeline, tank, or tanker. Since these asphaltene flocs are usually only a few micrometers, they often can be transported without settling out or causing deposition problems. However, if these insoluble asphaltenes contact a hot surface above 300 °C, the asphaltene flocs can melt, stick to the surface, and form coke that cannot be dissolved. For instance, Figure 11 shows an apparatus used 4010
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
the small amount of insoluble asphaltenes would result in smaller flocs when precipitated and the combination would cause slow kinetics of fouling in a flowing system, as compared to when the solubility blending number of the medium is well below the insolubility number of one of the component oils. However, nearly incompatible oils have already been observed to be slower fouling than incompatible oils.19 Therefore, this author takes a pragmatic stand on the question of asphaltene precipitation kinetics. For the oil compatibility tests, the sit time cannot be practically increased much higher than 5 min because many trial and errors steps are required to determine each point of incipient precipitation. Certainly, waiting for several days for each step is out of the question. The concept of a single flocculation solubility parameter for each oil containing asphaltenes has been verified. The use of the oil compatibility model for defining an operating window for low or no organic fouling has been successful and the effect of precipitation kinetics is greatest in the region already identified as nearly incompatible. Therefore, while the effect of asphaltene precipitation kinetics will not be ignored, the oil compatibility tests and predictions with the oil compatibility model will not be greatly changed. An exception is when a crude oil has a high viscosity, the temperature of the sit time is raised to 80 °C (boiling points of toluene and n-heptane are close to 100 °C). No matter the slow kinetics for asphaltene precipitation, the kinetics for dissolving precipitated asphaltenes is at least an order of magnitude slower. This is why mixing potentially incompatible Souedie and Forties in the wrong order (adding Souedie to Forties) in a tank produced rapid fouling and coking in a refinery even though the final proportions were in the compatible range.16 This is in contrast to when Forties was added to Souedie in the same proportions and no observable fouling or coking resulted.
the definition of insoluble asphaltenes is somewhat arbitrary. For the oil compatibility tests, insoluble asphaltenes are detected by an optical microscope with a resolution limit of about one micrometer at the magnification used (100×). From X-ray diffraction, small-angle X-ray scattering, or small angle neutron scattering, one knows that asphaltenes in crude oils aggregate into particles of about 4 nm. By adding a nonsolvent, these asphaltene aggregates grow in size until they reach the size of 1000 nm (1 μm) that one detects as an insoluble asphaltene. The rate of aggregation must depend on the quantity of asphaltenes, the degree of super saturation, and the viscosity of the medium. Mason and Lin22 used dynamic, small angle neutron scattering to measure the time dependent aggregation of asphaltenes at room temperature when mixing the incompatible crude oils, Souedie and Forties, a system studied previously by this author. 16,19 While the oil compatibility model predicts asphaltene insolubility above a Forties volume fraction of 0.67, Mason and Lin detect greater asphaltene agglomeration above a Forties volume fraction of 0.47 and this agglomeration at room temperature continued to increase after two days. Maqbool, Balgoa, and Fogler6 used optical microscopy and centrifugation to study the rate of asphaltene precipitation of asphaltenes at room temperature from an Alaskan crude oil after the addition of n-heptane. The precipitation onset time varied between a few minutes and several months, depending on the heptane concentration. The longest time was when the amount of precipitated asphaltenes was low, requiring a long time for the asphaltene particles to find each other. Meanwhile, Maqbool, Srikiratiwong, and Fogler23 concluded that the precipitation onset time was shorter at higher temperatures (about 2.5 times faster at 50 °C as compared with 20 °C), even though the asphaltene solubility was greater at the higher temperature, chiefly because of the lower viscosity. They also concluded that no single concentration can be identified as the critical precipitant concentration for asphaltene precipitation. Thus, they do not believe in the heptane dilution test. The effect of the rate of precipitation of asphaltenes is a legitimate concern for both the oil compatibility tests and its applications. However, by keeping the time between mixing and asphaltene detection at 5 min at 60 °C, the measurement of the point of incipient asphaltene precipitation in both the heptane dilution and toluene equivalence tests is quite reproducible. In addition, plots like Figure 9 are always found to be linear, which verifies the concept of a single flocculation solubility parameter for each oil that contains asphaltenes. Nevertheless, the concern is that when the measured solubility blending number of the mixture is slightly higher than the highest measured insolubility number of the oils in the blend, the range is called nearly incompatible. If asphaltenes are still precipitated because the sit time of the oil compatibility tests was too short to detect asphaltene precipitation, the amount of asphaltene precipitation will be small, and this is what causes the kinetics of precipitation to be slow. If the mixing of crudes at a refinery is in line, the process time scale is of the order of minutes at temperatures much higher than the 60 °C in the laboratory tests. While the refinery precipitation kinetics is much faster at the higher temperature, more likely, in the nearly incompatible range, asphaltenes become soluble before they can precipitate. On the other hand, crudes can be mixed in a tank at ambient temperatures and let sit for hours or days. Therefore, asphaltenes might precipitate at the longer time in a tank as compared with 5 min at 60 °C in the laboratory tests. However,
■
REGULAR FLORY−HUGGINS SOLUTION MODEL The regular solution model is considered to be only a semiquantitative approximation for mixtures of nonpolar, low molecular weight liquids.24 This author has found that, for many liquid mixtures, the solubility parameter, originally defined by the regular solution model, is more useful than the regular solution model itself.7 This is why the oil compatibility model uses solubility parameters but not the regular solution model. Nevertheless, an attempt was made to see if the oil compatibility model could predict incipient asphaltene precipitation of other solvent−nonsolvent mixtures based on the data obtained using toluene and n-heptane, knowing that this cannot be done for any other system.24 First, an attempt was made to use cyclohexane (solvent in Figure 8) to replace toluene in the toluene equivalence test to form the cyclohexane equivalence test. Becuse the solubility parameter of the mixtures at the point of incipient asphaltene phase separation are equal to the flocculation solubility parameter, the cyclohexane equivalence, CE, can be calculated from the toluene equivalence, TE, and the solubility parameters for toluene, δT, for n-heptane, δH, and for cyclohexane, δC.7 CE = TE
(δ T − δ H ) (8.93 − 7.50) = 2.07TE = TE (8.19 − 7.50) (δC − δ H) (8)
Table 3 shows good agreement with experimental cyclohexane equivalences with those calculated by eq 8 for three different crude oils. Even chlorobenzene, with a electronegative 4011
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
Table 3. Calculation of Cyclohexane Equivalence from Toluene Equivalence7 toluene
cyclohexane equiv
crude oil
equiv
calcd
exptl
A B C
30 12 27
62 25 56
64 23 58
atom, can replace toluene in the toluene equivalence test and give the expected values based upon solubility parameters.17 Second, one should consider replacing n-heptane in the heptane dilution test by other nonsolvents, with other normal paraffins being the obvious choice. However, while the normal paraffins increase solubility parameter with increasing carbon number, the volume of nonsolvents at the point of incipient asphaltene precipitation increases with carbon number; it goes through a maximum about at nonane and then decreases at higher carbon numbers. Hexadecane usually precipitates asphaltenes at a much lower volume than n-heptane. The oil compatibility model clearly cannot predict this behavior. Chain molecules increase entropy of mixing with increasing chain length for greater solubility but also increase the heat of mixing with increasing chain length for lower solubility. As solubility is governed by Gibbs free energy, the result is that the solvency will go through a maximum with increasing paraffin carbon number.25 The simplest modification of the oil compatibility model to include normal paraffins is to determine an effective solubility blending number for each normal paraffin by the same procedure as for nonsolvent oils without asphaltenes. This was done for five different crude oils and the solubility blending numbers were averaged for each normal paraffin as shown in Table 4. Those that have negative values indicate that they are
Figure 12. Comparison of experimental data of the volume fraction of n-paraffins at the onset of asphaltene precipitation with three methods of calculation for Athabasca bitumen. Reprinted with permission from ref 25. Copyright 2005, American Chemical Society.
mixing prediction of the regular solution model and the entropy of mixing prediction of the Flory−Huggins model. Although this was derived for polymer solutions, even Flory26 admitted that rubber−benzene was the only polymer solution quantitatively described by this model. Still, this model qualitatively describes many features of polymer solutions. Nevertheless, the expectation of success of this model for petroleum solutions should not be high. The multicomponent (n-components) regular Flory−Huggins model for the chemical potential of component i, μi, is given by
Table 4. Effective Solubility Blending Numbers of Normal Paraffins20 n-paraffin carbon no.
avg effective solubility blending no.
5 6 7 8 9 10 11 12 13 14 15 16
−6.13 −2.07 0.00 0.83 1.46 1.01 0.11 −2.12 −3.72 −5.28 −7.73 −10.05
μi − μi * RT
j=n
= ln(ϕi) + 1 −
∑ rijϕj + j=1
= ln(Xiγi)
vi(δi − δM)2 RT (9)
where μi* = standard chemical potential of pure component i, R = gas constant, T = absolute temperature, xi = mole fraction of component i, vi = molar volume of component i, ϕi = volume fraction of component i = xivi/(∑ xivi), rij = vi/vj, δi = solubility parameter of component i, δM = solubility parameter of the mixture = ∑ϕi δi, and γi = activity coefficient of component i. Hirschberg27 made the simplifying assumption that a mixture of asphaltenes, maltenes, and liquid could be treated as a binary, with asphaltenes as one component and maltenes and liquid as the second component. He also assumed that the asphaltenerich phase contained only asphaltenes and that the asphaltenes are dilute at the flocculation point. On the other hand, Cimino28 assumed that all the asphaltenes precipitate at the point of phase separation leaving a phase that contains no asphaltenes. As a result, they predicted the maximum volume of n-paraffin at the flocculation point was for n-octane. Wang and Buckley29 also made the pseudo-binary approximation but required the maltenes and paraffin to be in the same ratio in both phases. They successfully applied their model to describe quantitatively the change of refractive index of crude oils in nparaffins at the onset of asphaltene precipitation. Yarranton30 used similar approximations as Hirschberg except Yarranton
poorer solvents than n-heptane. One can see that long chain paraffins are strong precipitants for initiating asphaltene precipitation. However, at high dilutions in normal paraffins the amount of solids participated decreases with increasing paraffin carbon number.25 Nevertheless, a comparison between experimental and calculated volume fraction paraffin at the point of incipient asphaltene precipitation is shown in Figure 12 for Athabsca bitumen using effective solubility blending numbers for the normal paraffins. The simplest solution thermodynamic model that can approximate the entropy and heat of mixing chain molecules is the regular Flory−Huggins model. This contains the heat of 4012
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
■
Review
LIVE CRUDE OILS The objective of many is to apply this understanding of asphaltene solubility to determine when insoluble asphaltenes will be a problem during petroleum production. Figure 13
greatly increased the number of components to include nparaffin, saturates, aromatics, resins, and associated asphaltenes with a molecular weight distribution. Instead of assuming the asphaltene-rich phase was only asphaltenes, he assumed it contained asphaltenes and resins. The Yarranton model was able quantitatively to describe the fractional yield of precipitated asphaltenes as a function of the dilution of Athabasca bitumen in n-pentane, n-hexane, and n-heptane at 23 °C. In addition, this model gave reasonable predictions of the maximum in volume fraction of paraffin at the point of incipient asphaltene precipitation as a function of normal paraffin carbon number without adding any new constants, as shown in Figure 12. The regular Flory−Huggins model is extremely sensitive to the values of the solubility parameters with differences in the fourth decimal place being important. Yarranton calculated solubility parameters for paraffins from a correlation based on heat of vaporization and molar volume data, while Wang and Buckley used a correlation with refractive index data. Figure 12 shows the predictions based on the two estimates of paraffin solubility parameters. More recently, Kumar et al.31 applied the Yarranton model to predict the precipitation of asphaltenes from crude oil blends. In conclusion, the use of solubility parameters and the regular Flory−Huggins model to quantitatively describe asphaltene solubility is much better than one should expect based upon the lack of quantitative success of these applied to polymer and low molecular weight liquids. It is clear that they are more successful with petroleum systems than any other system, and they provide useful tools that have been successfully applied to solve asphaltene solubility problems in the petroleum industry. Instead of being amazed at the success of solubility parameters and the regular Flory−Huggins model, Nikooyeh and Shaw5 have exaggerated their defects. These authors criticize the regular solution model for not describing accurately their own data on partial specific volume and heat of mixing of asphaltenes in various liquids at near infinite dilution. However, they neglect to report that the regular solution model does not describe accurately the partial specific volume and heat of mixing of simple liquid mixtures. The regular solution model was derived on the assumption of zero volume of mixing, and it is well-known that it cannot predict the heat of mixing.24
Figure 13. The equation of state model of Firoozabadi30 describes the precipitation of asphaltenes from a live oil as the pressure is decreased to the bubble (saturation) point (data of Hirschberg22for a crude oil and propane at 94 °C). Copyright 1999 from Thermodynamics of Hydrocarbon Reservoirs by A. Firoozabadi. Reproduced by permission of McGraw−Hill.
shows the behavior of a live oil (simulated with propane) as a function of pressure that has an asphaltene insolubility problem. At high reservoir pressures the dissolved gases in a live oil, such as methane, have a moderate solubility parameter and occupy a low volume fraction of the oil. As the pressure is decreased during production in a well bore, the solubility parameter of the dissolved gases decreases and their volume fraction in the oil increases. If the solubility parameter of the dead oil (also called tank oil) is not much higher than its flocculation solubility parameter and if the gas to oil ratio is high, the combination of low solubility parameter of the dissolved gases and their higher volume fraction can make the solubility parameter of the live oil drop below the flocculation solubility parameter at conditions, and asphaltenes will precipitate. More asphaltenes will precipitate as the pressure is decreased further until reaching the bubble point where the dissolved gases escape the liquid phase and the liquid again becomes a solvent for asphaltenes. As opposed to dead oils, asphaltene solubility in live oils often decreases with increasing temperature. Nevertheless, an equation of state model is required to describe quantitatively how the solubility parameter and volume fraction of the dissolved gases vary with pressure and temperature. In addition, one needs to extrapolate the flocculation solubility parameter and solubility parameter of the dead oil from near atmospheric conditions to the temperature and pressure of the reservoir. Figure 13 shows that the equation state model of Firoozabadi37 can describe the quantity of precipitated asphaltenes with pressure. However, this model does not take advantage of the measurements at ambient conditions but fits constants from high pressure data. One prefers to only use experiments on the dead oil at ambient conditions to predict the phase behavior, including asphaltene solubility, at reservoir conditions. If one only needed to know whether or not a petroleum reservoir is expected to have an insoluble asphaltene problem, one could determine this from the flocculation solubility parameter and solubility parameter of the dead oil
■
SAFT EQUATION OF STATE The SAFT (statistical associating fluid theory) equation of state32 in contrast to the regular Flory−Huggins model extends the modern Wertheim33 theory to account for molecular interactions and the mixing of chain molecules. In addition, the association part accounts for complex formation between molecules. Gross and Sadowski34 developed the perturbed chain modification of SAFT (PC-SAFT). However, both SAFT and PC-SAFT are very mathematically complex models. Nevertheless, the PC-SAFT equation of state has found great success in quantitatively describing the phase equilibria of polymer mixtures. When SAFT was applied to petroleum, Ting, Chapman, and Hirasaki35 determined that it was not necessary to include asphaltene association as complex formation and verified that the onset of asphaltene precipitation occurs at nearly constant solubility parameter, in agreement with the conclusions in this paper. 4013
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
(insolubility number and solubility blending number), the gas to oil ratio of the live oil, and the dissolved gas composition of the live oil. This is essentially the approach used by Kraiwattanawong et al.,38 who used an empirical correlation between the onset (flocculation) solubility parameter and the molar volume of precipitants to estimate the effect of dissolved gas on the flocculation solubility parameter of live oil. The Hirschberg approximation to the regular Flory−Huggins model, including that the insoluble phase only contains asphaltenes, was used to extend the solubility parameters of live oil to higher temperatures and pressures. The end result was that solubility parameters of a tank oil coupled with the Peng−Robinson equation of state model of the PVT data of live oils were used to predict the asphaltene instability of a live oil system, as is shown in Figure 14. Figure 15. Insoluble asphaltene yield from a live oil at three temperatures, from Tharanivasan et al. Reprinted with permission from ref 32. Copyright 1990, American Chemical Society.
were determined from titrations of the model oil and the tank oil with C7, C11, and C15 normal paraffins to determine the volume fraction and refractive index at each onset and fitting these with PC-SAFT. Figure 16 is an example comparison
Figure 14. Comparison of model prediction with experimental data on a live oil from Kraiwattanawong et al. Reprinted with permission from ref 31. Copyright 2009, American Chemical Society.
Tharanivasan, Yarranton, and Taylor 39 have applied Yarranton approximations to the regular Flory−Huggins model and empirical equations for densities of liquids, effective liquid densities of dissolved gases, and heats of vaporization to obtain the functional relationships of the variation of the solubility parameter with temperature and pressure for components of a Gulf of Mexico crude oil recombined with a synthetic solution gas to match the desired gas/oil ratio. This model both predicted the insoluble asphaltene yield data on diluting the dead oil with n-heptane and the asphaltene yield data below the onset pressure for the live oil (Figure 15). The only adjustable parameter was the average molecular weight of the asphaltene “nanoaggregates” that decreased from 2900 at 80 °C to 2620 at 120 °C. The PC-SAFT equation of state has proven to model successfully petroleum systems, including predicting bubble points and onsets of asphaltene precipitation with a minimum of required data while taking advantage of ambient condition titration data. For instance, Ting, Hirasaki, and Chapman40 applied PC-SAFT to a model oil composed of n-heptane, toluene, asphaltenes, and methane and to a tank oil recombined with its separator gases. The recombined oil was assumed to be composed of three components of gas: methane, light alkanes, and nitrogen + carbon dioxide, and three components of oil: saturates, aromatics + resins, and asphaltenes. The SAFT parameters for saturates and aromatics + resins were obtained for correlations with molecular weights for each class of compound. The SAFT parameters for asphaltenes in each case
Figure 16. Experimental bubble points (filled symbols) and asphaltene onsets (open symbols) compared with calculations of PC-SAFT (lines) for a model oil at two different temperatures, from Vargas et al. Reprinted with permission from ref 34. Copyright 2001, American Chemical Society.
between experimental points and calculations of the resulting PC-SAFT for the bubble point and asphaltene precipitation onset curves for the model oil at 68 °F and at 150 °F on a plot of pressure versus methane mole fraction.41 Recently, Vargus et al.36 have obtained universal plots for the bubble point and the onset of asphaltene precipitation. As part of this study, they proposed a new mixing rule for determining the solubility parameter of a mixture of liquids and dissolved gases, δmix: δmix 2 =
∑ ϕδi i 2 i
where ϕi = volume fraction of component i and δi = solubility parameter of component i. In the applications of the PC-SAFT model to petroleum fluids the asphaltene molecular weights were taken as from 1700 to 4000 and in application of the regular Flory−Huggins 4014
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
■
model values of 2620−2900 were used. While both sets of authors called these “nanoaggregates” to fit into the popular belief that asphaltenes should have average molecular weights of the order of 700, the only way that “nanoaggregates” could be so tightly held together over a large range of temperature, of dilution, and of solvency is if they are covalently bonded and these are the actual average molecular weights of asphaltene molecules.
REFERENCES
(1) Buenrostro-Gonzalez, E.; Groenzin, H.; Lira-Galeana, C.; Mullins, O. C. The overriding chemical principles that define asphaltenes. Energy Fuels 2001, 15, 972−978. (2) Mullins, O. C. The modified Yen model. Energy Fuels 2010, 24, 2179−2207. (3) Zhao, B.; Shaw, J. M. Composition and size distribution of coherent nanostructures in Athabasca bitumen and Maya Crude Oil. Energy Fuels 2007, 21, 2795−2804. (4) Mullins, O. C.; Betancourt, S. S.; Cribbs, M. E.; Dubost, F. X.; Creek, J. L.; Andrews, A. B.; Venkataramanan, L. The colloidal structure of crude oil and the structure of oil reservoirs. Energy Fuels 2007, 21, 2785−2794. (5) Nikooyeh, K.; Shaw, J. M. On the applicability of the regular solution theory to asphaltene + diluent mixtures. Energy Fuels 2011, 26, 576−585. (6) Maqbool, T.; Balgoa, A. T.; Fogler, H. S. Revisiting asphaltene precipitation from crude oils: A case of neglected kinetic effects. Energy Fuels 2009, 23, 3681−3686. (7) Wiehe, I. A. Process Chemistry of Petroleum Macromolecules; CRC Press: Boca Raton, FL, 2008. (8) Wiehe, I. A. Two-dimensional solubility parameter mapping of heavy oils. Fuel Sci. Technol. Int. 1996, 14, 289−312. (9) Wiehe, I. A.; Liang, K. S. Asphaltenes, resins, and other petroleum macromolecules. Fluid Phase Equilib. 1996, 117, 201−210. (10) Pfeiffer, J. P.; Saal, R. N. Asphaltic bitumen as colloidal system. J. Phys. Chem. 1940, 44, 139−145. (11) Rogel, E. Molecular thermodynamic approach to the formation of mixed asphaltene−resin aggregates. Energy Fuels 2008, 22, 3922− 3929. (12) Sedghi, M.; Goual, L. Role of resins on asphaltene stability. Energy Fuels 2010, 24, 2275−2280. (13) Wiehe, I. A.; Jermansen, T. G. Design of synthetic dispersants for asphaltenes. Pet. Sci. Technol. 2003, 21, 527−536. (14) Wang, J.; Buckley, J. S. Asphaltene-stability in crude oil and aromatic solventsThe influence of oil composition. Energy Fuels 2003, 17, 1445−1451. (15) Wiehe, I. A. Self-incompatible crude oils and converted petroleum resids. J. Dispersion Sci. Technol. 2004, 25, 333−339. (16) Wiehe, I. A.; Kennedy, R. J. The oil compatibility model and crude oil compatibility. Energy Fuels 2000, 14, 56−59. (17) Wiehe, I. A.; Kennedy, R. J. Application of the oil compatibility model to refinery streams. Energy Fuels 2000, 14, 60−63. (18) Wiehe, I. A.; Kennedy, R. J. Process for Blending Potentially Incompatible Petroleum Oils, U.S. Patent No. 5,871,634. Assigned to Exxon, 1999. (19) Wiehe, I. A.; Kennedy, R. J.; Dickakian, G. Fouling of nearly incompatible oils. Energy Fuels 2001, 15, 1057−1058. (20) Wiehe, I. A.; Kennedy, R. J. Process for Blending Petroleum Oils to Avoid Being Nearly Incompatible. U.S. Patent No. 5,997,723. Assigned to Exxon, 1999. (21) Shah, P.; Ramaswamy, P. N.; Knight, M. Increased fouling potential and mitigation plans for heavy sour crude oils. AIChE Spring National Meeting, Chicago, 2011 (22) Mason, T. G.; Lin, M. Y. Time-resolved small angle neutron scattering measurements of asphaltene nanoparticle aggregation kinetics in incompatible crude oil mixtures. J. Chem. Phys. 2003, 119 (1), 565−571. (23) Maqbool, T.; Srikratiwong, P.; Fogler, H. S. Effect of temperature on the precipitation kinetics of asphaltenes. Energy Fuels 2011, 25, 694−700. (24) Prausnitz, J. M. Molecular Thermodynamics of Fluid-Phase Equilibria; Prentice-Hall: Englewood Cliffs, NJ, 1969. (25) Wiehe, I. A.; Yarranton, H. W.; Akbarzadeh, K; Rahimi, P. M.; Teclemariam, A. The paradox of asphaltene precipitation with normal paraffins. Energy Fuels 2005, 19, 1261−1267. (26) Flory, P. J. Principles of Polymer Chemistry; Cornell University Press: Ithaca, NY, 1953; pp 554−555.
■
CONCLUSIONS This review has shown that recent studies reputed to establish new concepts about the chemical structure of petroleum and its physical interactions may be premature. The concept that asphaltenes have average molecular weight of the order of 700 does not explain why only a minor fraction of asphaltenes evaporate during refinery processing at 500 °C under a high flow of steam and these evaporated asphaltenes have a molecular weight of the order of 700. In contrast to several recent results, the overwhelming evidence is that resins solubilize asphaltenes by more than just acting as a solvent. Although the resin−asphaltene interaction is not a specific interaction, like hydrogen bonding, it is likely an interaction between large, flat polynuclear aromatics through dispersion forces. While the use of solubility parameters and the regular Flory− Huggins model are only rough approximations when applied to predict the solubility of low molecular weight and polymer systems, they provide good approximations when applied to petroleum systems. The volume average mixing rule for solubility parameters provides the basis for the oil compatibility model that successfully predicts the compatibility operating window for mixtures of oils from data only on the component oils. This model also enables predicting the solubility of an oil in mixtures of cyclohexane and n-heptane and in chlorobenzene and n-heptane based upon data of that oil in toluene and nheptane. The regular Flory−Huggins model correctly predicts that the volume of normal paraffin at the flocculation point for a crude oil has a maximum when plotted against the normal paraffin carbon number but at high dilutions in the normal paraffins the amount of asphaltenes precipitated decreases with increasing normal paraffin carbon number. The slow rate of precipitation of asphaltenes is a legitimate concern for both oil flocculation tests and applications of the Oil Compatibility Model. Fortunately, the errors introduced are greatest for nearly incompatible oils that at worst only cause a slow rate of fouling. This effect previously was attributed to the adsorption of asphaltenes on hot surfaces. The objective for applications to live oils is to use only experiments on the dead oil at ambient conditions to predict asphaltene solubility of the live oil at reservoir conditions. This has been successfully accomplished using either the regular Flory−Huggins equation or the PC-SAFT equation of state. However, the average molecular weight of the asphaltenes had to be assumed to be 1700−4000, depending on the system.
■
Review
AUTHOR INFORMATION
Corresponding Author
*Email:
[email protected]. Notes
The authors declare no competing financial interest. 4015
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
Energy & Fuels
Review
(27) Hirschberg, A.; de Jong, N. J.; Schipper, B. A.; Meijers, J. G. Influence of temperature and pressure on asphaltene flocculation. Soc. Pet. Eng. 1984, 6, 283−293. (28) Cimino, R.; Correra, S.; Del Bianco, A.; Lockhart, T. P. Solubility and phase behavior of asphaltenes in hydrocarbon media. In Asphaltenes Fundamentals and Applications. Sheu, E. Y.; Mullins, O. C., Eds.; Plenum Press: New York, 1995; pp 97−130. (29) Wang, J. X.; Buckley, J. S. A two-component model of the onset of asphaltene flocculation in crude oils. Energy Fuels 2001, 15, 1004− 1012. (30) Alboudwarej, H.; Akbarzadeh, K.; Beck, J.; Svrewk, W. Y.; Yarranton, H. W. Regular solution model for asphaltene precipitation from bitumens and solvents. AIChE J. 2003, 49, 2948−2956. (31) Tharanivasan, A. K.; Svrcek, W. Y.; Yarranton, H. W. Measurement and modeling of asphaltene precipitation from crude oil blends. Energy Fuels 2009, 23, 3971−3980. (32) Chapman, W. G.; Gubbins, K. E.; Jackson, G.; Radosz, M. Ind. Eng. Chem. Res 1990, 29, 1709−1721. (33) Wertheim, M. S. J. Stat. Phys. 1986, 42, 459−492. (34) Gross, J.; Sadowski, G. Ind. Eng. Chem. Res. 2001, 40, 1244− 1260. (35) Ting, P. D.; Chapman, W. G.; Hirasaki, G. J. Asphaltene phase behavior: Experiment and modeling using the SAFT equation of state. Proceedings of the 3rd International Conference on Petroleum Phase Behavior and Fouling; Wiehe, I. A., Ed.; AIChE: New York, 2002; pp 204−210. (36) Firoozabadi, A. Thermodynamics of Hydrocarbon Reservoirs; McGraw-Hill: New York, 1999; p 328. (37) Kraiwattanawong, K.; Fogler, H. S.; Gharfeh, S. G.; Singh, P.; Thomason, W. H.; Chavadej, S. Thermodynamic solubility models to predict asphaltene instability in live crude oils. Energy Fuels 2007, 21, 1248−1255. (38) Tharanivasan, A. K.; Yarranton, H. W.; Taylor, S. D. Application of a regular solution-based model to asphaltene precipitation from live oils. Energy Fuels 2011, 25, 528−538. (39) Ting, P. D.; Hirasaki, G. J.; Chapman, W. G. Modeling of asphaltene phase behavior with the SAFT equation of state. Pet. Sci. Technol. 2003, 21, 647−661. (40) Vargas, F. A.; Gonzalez, D. L.; Hirasaki, G. J.; Chapman, W. G. Modeling asphaltene phase behavior in crude oil systems using the perturbed chain form of the statistical associating fluid theory (PCSAFT) Equation of State. Energy Fuels 2009, 23, 1140−1146. (41) Vargas, F. A.; Gonzalez, D. L.; Creek, J. L.; Wang, J.; Buckley, J.; Hirasaki, G. J.; Chapman, W. G. Development of a general method for modeling asphaltene stability. Energy Fuels 2009, 23, 1147−1154.
4016
dx.doi.org/10.1021/ef300276x | Energy Fuels 2012, 26, 4004−4016
