Freedom of Action in the State of Asphaltenes: Escape from

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Freedom of Action in the State of Asphaltenes: Escape from Conventional Wisdom† Jefferson L. Creek* Chevron Energy Technology Company, Houston, Texas 77082 Received September 3, 2004. Revised Manuscript Received May 12, 2005

The “plus” fraction of a petroleum fluid is a complex mixture that has long defied traditional chemical and thermodynamic treatments. This fraction of crude oil, by and large, cannot be analyzed. These fractions contain quantities identified as asphaltenes and resins that are solubility classes and, as such, are particularly difficult to characterize. Despite generations of study with ever-more-powerful scientific tools, the research community still has difficulty determining the physical and chemical properties of asphaltenes, and there is still no agreement regarding how these materials should be studied. To some extent, these difficulties may be inherent in the complexity of the petroleum fluids, but they have also been exacerbated by the acceptance of “conventional” wisdom. The “purists” at one end of the spectrum study only single-phase samples of live oil; however, experiments on such fluids samples are expensive and difficult, because of the typical high pressures that are encountered. At the opposite extreme are mechanistic studies that focus on isolated asphaltene fractions (model systems), where asphaltenes are precipitated from one source and then studied in a solvent completely different from the original crude oil from which they originated. Such research suffers from an imperfect model for asphaltenes in their natural environment. This paper will examine the successes and failures in applying scientific principles to asphaltenes and the flaw of assuming, either directly or tacitly, that asphaltenes and resins are a compound that has a structure that can be defined and has a separate identity that can be determined by isolating the class of compounds from their “native” state. New research that points a way forward is also discussed.

Introduction Asphaltene deposition in wellbores and flow lines is of intense interest in the petroleum industry for the development of deepwater fields. Figure 1 graphically illustrates what has been termed by Kokal and Sayegh1 to be “the cholesterol of petroleum”. Asphaltenes may deposit in the “near well bore” region of the reservoir or, more typically, in the production tubing. The arterial deposition reduces flow as the deposit thickness increases. The reduced flow is associated with a loss in revenue to a point that requires remediation. The removal or reduction of asphaltene deposits can cost as little as $0.5 MM U.S. for coiled tubing on land or in shallow water to $3 MM U.S. or more for a deepwater well where entry into the wellbore is required. These figures are approximate estimates and do not include lost production, which can amount to $1,200,000 per day (e.g., 40 MBOD at $30/BBL translates to ∼$1.2 MMPD). Recent advances in understanding the driving force involved with asphaltene precipitation and a general understanding of the arterial deposition in flow lines have improved matters. What is still lacking is a † Presented at the 5th International Conference on Petroleum Phase Behavior and Fouling. * Author to whom correspondence should be addressed. E-mail address: [email protected]. (1) Kokal, S. L.; Sayegh, S. G. Asphaltenes: The Cholesterol of Petroleum. Presented at the SPE Middle East Oil Show, 1985, SPE Paper No. 29787.

Figure 1. Cholesterol of petroleum.

determination of composition of the oil in a manner appropriate to the deposition and precipitation of the material in question: asphaltenes. Asphaltenes have been greatly studied, but to what end? For all of the effort expended since the original definition of asphaltenes by J. B. Boussingault in 1837, their precipitation and deposition are scarcely understood.2 I suppose that much of the work has been good for the refining and asphalt industry. How does the existing literature impact subsea developments, which are the chief interest of the flow assurance engineer in the development of petroleum capital assets? Modern (2) Mansoori, G. A. Nanoscale Structures of Asphaltene Molecule, Asphaltene Steric-Colloid and Asphaltene Micelles & Vesicles. Available via the Internet at http://tigger.uic.edu/∼mansoori/ Asphaltene.Molecule_html.

10.1021/ef049778m CCC: $30.25 © 2005 American Chemical Society Published on Web 07/06/2005

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Figure 2. Separation scheme for petroleum.

flow assurance engineers must (i) forecast if there will be a problem and (ii) if there is a problem, determine the magnitude of the problem and whether can it be resolved. The title of this presentation, “Freedom of Action in the State of Asphaltenes: Escape from Conventional Wisdom”, was meant to highlight much of the confusion and the potential problems in our current approach. What intellectual traps in the approach have caused problems in the past? One might be the tacit assumption of the independence of the observer and the observed. Although one could wish this were true, it is, in fact, quite difficult to execute measurements in this fashion. Can meaningful data be obtained with the “asphaltenes” in a different matrix than the original solvent oil? Here, the method of examination, isolating “asphaltenes” in a foreign solvent, conditions the response, as will be shown later. First, What is the Definition of an Asphaltene? There are several definitions of an asphaltene: •Boussingault in 1837 defined “asphaltene” as the alcohol-insoluble, turpentine-soluble solid obtained from the distillation residue.2 • It has been said that “asphaltenes and resins are difficult to define, even when a standard procedure is employed”. • The operational definition of an asphaltene is material that (i) precipitates from oil when diluted 20:1 or more with paraffin solvents (n-C5, n-C7, ...) but is soluble in toluene; (ii) can be filtered at 1-1.5 µm (not extruded); and (iii) does not include contributions from resins and waxes. Primarily, asphaltenes are defined by a precipitation scheme such as that presented in Figure 2. A review of the many methods of determination of asphaltenes is given by Goual and Firoozabadi.3 If one examines all the chemicals and other data and compiles a structure that is consistent with these observations, one can arrive at the structures shown below in Figure 3.4 (3) Goual, L.; Firoozabadi, A. Asphaltene/Resin Analysis in Crudes, and Deposition/Precipitation and Inhibition Studies, RERI Report, Reservoir Engineering Research Institute, Palo Alto, CA, 2000.

Other measurements indicate that things are much more complicated and perhaps there is not one structure, or self-associated sheets of molecules, but a mixture of a broad spectrum of species, as indicated by the molecular weight distributions from size exclusion chromatography shown in Figure 4. Figure 5 shows a different view of the same phenomena. In this figure, one sees the distribution primarily of the polar species in oil, using electrospray mass spectroscopy (EMS). This figure shows the intensity of a wide range of species (mass m divided by the charge z) for thousands of species (or as well as can be resolved) from m/z ) 250 to m/z ≈ 800. Can One Imagine an Average Asphaltene Molecule? Could one envision an average person from last year’s meeting on petroleum phase beahvior and fouling? How would we decide the structure? By mass per unit? Voice pitch? Height? Cross-section? Age? Electron density? Elemental analysis? Given the wide variety of attendees, such categorization does not seem likely. Consider the general composition of oil and how the asphaltenes may be represented as a subfraction of all the species present, based on solubility. Extensive work in this area has been presented in the series of work by Altgelt and Boduszynski, “Composition and Analysis of Heavy Petroleum Fractions”.5 Figures 6 and 7 illustrate the variety of species present, as well as how generalizations might work in determining composition. (4) Kilpatrick, P. K. Colloidal and Interfacial Phenomena in Petroleum: Emulsions in Heavy Petroleum Fluids and Their Mixtures. Presented at the AIChE Spring National Meeting, Short Course on Colloidal and Interfacial Phenomena in Petroleum Production, March 10, 2002. (5) Altgelt, K. H.; Boduszynski, M. M. Composition and Analysis of Heavy Petroleum Fractions; Chemical Industries Series, Vol. 54; Marcel Dekker: New York, 1993. (b) Boduszynski, M. M. Composition of Heavy Petroleums. 1. Molecular Weight, Hydrogen Deficiency, and Heteroatom Concentration as a Function of Atmospheric Equivalent Boiling Point up to 1400 °F (760 °C). Energy Fuels 1987, 1, 2. (c) Boduszynski, M. M. Composition of Heavy Petroleums. 2. Molecular Characterization. Energy Fuels 1988, 2, 597. (d) Altgelt, K. H.; Boduszynski, M. M. Composition of Heavy Petroleums. 3. An Improving Boiling Point-Molecular Weight Relation. Energy Fuels 1992, 6, 68; (e) Boduszynski, M. M.; Altgelt, K. H. Composition of Heavy Petroleums. 4. Significance of the Extended Atmospheric Equivalent Boiling Point (AEBP) Scale. Energy Fuels 1992, 6, 72.

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Figure 3. Proposed structures for asphaltenes.

The gas chromatography (GC) analysis identifies normal paraffins, isoparaffins, cycloparaffins with both 5 and 6 carbons, rings with one and two methyl groups, and aromatic rings with single and multiple alkyl groups attached. It would be impossible to identify all the species present in a crude oil. Evidence indicates a wide boiling range with the numbers of components on the order of millions or perhaps even more numerous. For example, consider the possible number of paraffin isomers for a given number of carbons in a molecule:

Figure 4. Variation of molecular weights in asphaltenes.

There are multitudes of families of molecules present in crude oils. The structures shown in Figure 6 are just the major formal groups without all the molecules in the family with aliphatic side chains, etc. However, Figure 7 illustrates that, despite the variety of species, there can be some generalization of properties. Here, despite the wide variation in the gravity of the crude oils, what one sees is the similarity of the cut properties, with differences in the cut volumes making the difference in most properties. The Altamont oil is a special case that does not follow the general trend. Perhaps these exceptions will always exist. The hope would be that the important families that contribute to the physical properties could be included and form the basis for a distributed compositional representation analogous to that used to represent the C7+ fractions of oils for liquid vapor equilibrium. These two figures have shown a global view of the composition of oils. Figure 8 shows a more-detailed view of the composition over a limited range of carbon number in a crude oil. This figure shows the species present between the C6 and C8 compositional groups of a crude oil.

(1) For butane (n-C4), the number of isomers is 2. (2) For n-octane (n-C8), the number of isomers is 18. (3) For n-tetracosane (n-C44), the number of possible isomers is greater than 62 trillion (62 491 178 805 831).6 After examining the complexity of the composition of petroleum, one is driven to conclude that, despite generations of study with ever-more-powerful scientific tools, the research community still has difficulty determining the physical and chemical properties of these redissolved asphaltenes, and there is still no agreement regarding how they should be studied. To some extent, these difficulties may be inherent in the complexity of the petroleum fluids, but they have also been exacerbated by the acceptance of conventional wisdom. Precipitation Modeling One primary objective in the study of asphaltenes is the ability to simulate with confidence the observed phase separation. How would this be done? Typically, we would want to describe the state of the system. Classically, one would use the Gibbs’ phase rule:

f)c-p+2 where f is the number of degrees of freedom or the required number of independent variables needed to (6) Cram, D. J.; Hammond, G. S. Organic Chemistry; McGrawHill: New York, 1964.



Figure 5. Mass spectra of BG-5 asphaltenes.

Figure 6. Families of molecules present in crude oil, plotted as molecular weight versus boiling point.

describe the state of the system. For a binary system with one phase, three degrees of freedom would be required, including two of the three state variables P (pressure), V (volume), and T (temperature). The problem is what is the value of c, which represents the number of components for crude systems? How many of the infinite number of compositional variables present would be required? There are a few surprises in this regard. The number of compositional variables can be relatively few to describe certain general phenomena. This was illustrated in part by Figure 7, showing that the properties of five

crudes in six studied generally had the same cut properties. We could conceivably calculate the properties of a given crude by specifying the fractions of three of the four cuts and knowing the properties of the cuts. Another example is the general success of the simulation of precipitation onset of asphaltenes from solution using a Flory-Huggins theory-based approach. The Flory-Huggins theory is a lattice model with the pair potential taken from the Scatchard-Hildebrand Regular Solution Treatment. Regular solutions are described as “nonpolar”, with ∆SE and ∆VE each approximately equal to zero.7 This treatment gives some results

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Figure 7. Comparison of cut volumes and gravities for six crude oils.

Figure 8. Detailed composition of petroleum by high-resolution gas chromatography-mass spectroscopy (GC-MS).

indicating that, at least for simulations of the onset of precipitation, simple dispersion forces can be adequately used. There are usually two components: “oil” and “not-oil”. These models are, by definition, constrained to predicting, at most, two quantities exactly. For these models, it might be the onset of precipitation and the total amount of asphaltenes. From the “definition” of asphaltenes and resins, one would wonder how these could describe the complex precipitation behavior that is (7) Sandler, S. I. Chemical and Engineering Thermodynamics; Wiley: New York, 1999.

known to occur with asphaltenes. These models then are derived from regular solution theory. As such, the excess entropy should be approximately zero. This theory typically considers only nonpolar molecules, because the interaction parameter or cross term lij is set to zero and the assumption of ideal mixing is made. Asphaltenes are frequently considered to be the most polar fractions of petroleum. Asphaltenes are surely not polymers; however, they may consist of a variety of larger molecules and asphaltene species that are polarizable rather than polar. The success of these simple models in predicting the onset of precipitation is rather amazing.



Figure 9. Plot of asphaltene separation versus the precipitant/oil volume ratio. Solid line represents the model prediction, whereas the dotted line represents the polynomial fit (as determined by Wang and Buckley8).

Figure 10. Statistical Associating Fluid Theory (SAFT) predictions. (Data taken from Gonzalez, Chapman, and Hirasaki.)

Figure 9 , which has been reproduced from the work of Wang and Buckley,8 illustrates how the onset and total amount can be adequately modeled with a FloryHuggins-type theory. Precipitation of Asphaltenes as a Function of Precipitant Concentration. The model can predict the onset of precipitation and the total amount precipitated. It cannot predict the shape of the precipitation curve. The reason for this observation is that, after the onset of precipitation, each additional increment of precipitant precipitates different material than the previous increment. A much more complex characterization of the precipitating phase would be required. This is analogous to representing an oil in liquid-vapor (8) Wang, J.; Buckley, J. S. Improved Modeling of the Onset of Asphaltene Flocculation. Presented at the 2nd International Conference on Petroleum and Gas-Phase Behavior and Fouling, Copenhagen, August 27-31, 2000.

equilibrium measurement as methane and oil. Although this methodology works frequently with the aid of correlations, equations of state have difficulty representing general oil phase behavior in detail with a simple characterization of the fluid. The predictions by Ting et al.9 with Statistical Associating Fluid Theory (SAFT) show that increasing from a binary to a ternary description of the fluid enhances the model predictions significantly. These are depicted in Figure 10. A few attempts have already been made by Yarrington et al.10 These authors used a distribution function to represent the density as a function of molecular weight for the heavy components in an oil. These results are given in Figures 11 and 12. (9) Ting, D. P.; Gonzalez, D. L.; Wang, J.; Buckley, J. S.; Hirasaki, G. J.; Chapman, W. G. Prediction of Asphaltene DepositionsPhase III, CTR 6204 Final Report, January 2004.

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Figure 11. Results for the precipitation of material with heptane.10

Figure 12. Modeling of precipitation of asphaltenes from oil with heptane.

The idea of utilizing a polydisperse characterization for the oil has existed since 1987; however, little progress has been made.11,12 Definition Problems Again. A large part of the problem is the very definition of asphaltenes and resins. As Shaw and co-workers13 recently stated, asphaltenes are materials that precipitate from petroleum when the petroleum is mixed with at least a 20:1 excess of light paraffin hydrocarbon precipitant (e.g., n-heptane) that can be trapped on a 1-1.5 µm filter. Furthermore, the filtration process cannot happen so rapidly that the precipitated material is extruded through the filter paper. For example, if a second liquid phase is produced, as Shaw’s research has shown, one could encounter (10) Yarranton, H. W.; Beck, J.; Akbarzadeh, K.; Alboudwarej, H.; Svrcek, W. Y. Regular Solution Approach to Modeling Asphaltene Precipitation. Presented at the 4th International Conference on Phase Behavior and Fouling, Trondheim, Norway, June 2003. (11) Leontaritis, K. J.; Mansoori, G. A. Asphaltene Deposition During Oil Production and Processing: A Thermodynamic Colloidal Model. Presented at the SPE International Symposium on Oilfield Chemistry, February 4-6, 1987, San Antonio, TX, SPE Paper No. 16258. (12) Szewvzyk, V.; Behar, F.; Behar, E.; Scarcella, M. Evidence of the Physicochemical Polydispersity of Asphaltenes. Rev. Inst. Fr. Pet. 1996, 51 (4), 575-590. (13) Maham, Y.; Chodakowski, M.; Zhang, X.; Shaw, J. M. Asphaltene Phase Behavior: Prediction at a Crossroads. Presented at the Tenth International Conference on Properties and Phase Equilibria for Product and Process Design, Snowbird, UT, May 17-21, 2004.

relative permeability effects, where one phase passes preferentially through the filter while the other remains, giving an exaggerated interpretation of the amount of asphaltenes present and what their detailed compositions would be. Furthermore, the precipitate must be soluble in toluene. The exact precipitants and solvents used for the test vary, depending on who is performing the test. Issues as to whether the solvent chosen was heated to above the cloud point of the oil, to avoid wax precipitation, and the details of which solvent was used are also important to both the amount of material called asphaltenes and characteristics of the material precipitated. For example, it is well-documented that this is the case when one compares the amount and characteristics of the precipitated material when pentane, heptane, nonane, undecane, or pentadecane is used. Finally, to qualify as asphaltenes, the precipitated material must be soluble in aromatic solvents. Therefore, we have seen as much as a 5- to 10-fold difference in the asphaltene content for the same sample with the same technique! Resins have an even more vague definition and determination.4 It has been only natural to try to define the “asphaltenes” through determination of the physical properties of the precipitated or redissolved material. However,


attempts to characterize the precipitated material using typical physical measurements have proven confusing. Although the density seems relatively well-characterized (1.05-1.25 g/mL), the reported molecular weights, for example, range from 700 daltons to >10 000 daltons, depending on the technique used and the investigator. Similarly, other properties have been measured in many diverse ways, but often with confusing results. A clue exists in the work of Wiehe and Liang14 on a “twodimensional” solvent characterization matrix for asphaltenes. The exact solubility properties and amounts of material are dependent, in detail, on the source material, as well as the exact technique used. Solvents that work for one precipitated asphaltene material will not work for others. Shaw and co-workers13 recently reported that the fractal dimension for solutions of redissolved asphaltenes is substantially different and has a variable temperature difference, compared to the dimension determined from crude oil as a function of simple dilution with an aromatic solvent. The fact that the number of dimensions for the oil is greater than three indicates the source of the scattering is something other than particles. A fundamental assumption of science is the observer of an experimental event is independent of the experiment. Could it be that we significantly alter the response to a given question (query) by how we ask the question and what we think we see? If asphaltenes are known to be the “most polar” fraction of the oil, and asphaltenes are known to have a tendency to selfassociate, is it any wonder that experiments conducted where an attempt is made to redissolve the precipitate are doomed? Questions continue to exist as to how (or if) asphaltenes are even dissolved in oil. Model Systems Model systems of precipitated asphaltenes redissolved in a new solvent are not the only route forward. Mason and Lin15 have used mixtures of incompatible oils and time-resolved small-angle neutron scattering (TRSANS) to measure the kinetics of asphaltene aggregation in crude oils quantitatively. These TR-SANS data were interpreted as simple diffusion-limited kinetics and a repulsive potential barrier that models the effective solvent (fractal). An aggregation model that is based on a repulsive barrier in the average interaction potential between asphaltene particles that are dependent on the effective solvent quality was hypothesized to precisely account for the measured increase in the aggregation time from several hours to several days. Using a single pair potential to describe the average interactions between a wide variety of differently shaped asphaltene particles may be too simplistic, because the interactions may result from different sources and may be orientationdependent. (14) Wiehe, I. A.; Liang, K. S. Asphaltenes, Resins, and Other Petroleum Macromolecules. Presented at the Seventh International Conference on Properties and Phase Equilibria for Product and Process Design, Snowmass, CO, June 21-25, 1995. (15) 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.


Figure 13. Fractal dimension for dilute solutions of Athabasca Vacuum Bottoms (ABVB) and ABVB asphaltenes in 1-methyl naphthalene.

Figure 14. Fractal dimension for dilute solutions of ABVB and ABVB asphaltenes in dodecane.

An interesting series of experiments was performed by Shaw’s group at the University of Alberta13 to examine the state of organization in solutions of asphaltenes. A series of experiments were conducted using smallangle X-ray scattering on solutions and dilutions of oil and asphaltenes. The starting material was Athabasca vacuum bottoms. Spectra were obtained as a function of the temperature and properties proportional to the fraction dimension computed. A different ordering in solution was observed, regardless of whether the spectra studied were for the original sample, the original sample in R-methyl naphthalene, the asphaltenes from the sample, or the asphaltenes themselves. The results of this work are given in Figures 13 and 14. Similar results were found when normal dodecane, rather than the R-methyl naphthalene, was used as the solvent. The ordering of the sample varied greatly, depending on the nature of the solvent and the concentration. This implies that conclusions based on model studies about the physical properties of asphaltenes and their solubility may have little relevance to the situation in the original crude system. Asphaltenes as a Flow Assurance Concern. Typically, the flow assurance engineer is asked to determine if deposits will be a “problem” and if deposits will occur, how “bad” will the problem be. This would typically include hydrates, wax, asphaltenes, scale, and corrosion, where corrosion is a form of anti-deposition. Currently, only weak correlations are typically used to estimate

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Table 1. When Do Asphaltenes Precipitate?: The Resin-Asphaltene Ratio source of crude

°API

resin amount (wt %)

asphaltene amount (wt %)

resin/asphaltene ratio, R/A

Venezuela (Boscan) Mexico (Panucon) USA (Baxterville, MS) USA (Baxterville, MS) Russia (Kaluga) USA (Hould, TX) USA (Huntington Beach, CA) USA (Brookhaven, LA) Russia (Balachany) Russia (Bibi-Eibat) USA (Mexia, TX) Iraq (Kirkuk) Mexico (Tecoaminocan) Mexico (Isthmus) USA (Oklahoma City, OK) USA (OK, Tonkawa, OK)

10.2 11.7 16 16 16.7 19.7 26.2 30.6 31.7 32.1 36 36.1 36.7 37.8 38 40.8

29.4 26 8.9 8.9 20 12 19 4.6 6 9 5 15.5 8.8 8.1 5 2.5

17.2 12.5 17.2 17.2 0.5 0.5 4 1.65 0.5 0.3 1.3 1.3 1.5 1.3 0.1 0.2

1.7 2.1 0.5 0.5 40.0 24.0 4.8 2.8 12.0 30.0 3.8 11.9 5.9 6.2 50.0 12.5

whether asphaltenes deposition will be encountered. There has been much more success differentiating between systems that precipitate than determining those that deposit. Ideally, the flow assurance engineer would like to have a simulation tool that couples the physical phenomena with a measurable compositional variable so that one may “scale” the laboratory analysis to the field situation. More recently, there has been continuing concern about the deposition of asphaltenes in the reservoir. Several attempts have been made to study this phenomena; however, no clear path forward currently is available. Qin et al.16 have shown that the deposition in reservoirs may actually enhance production, because of mobility control in the reservoir as well as potentially impeded production. The situation would vary on a caseby-case basis, depending on the oil, the reservoir rock, and the method of production. However, note that few cases of reservoir damage have been reported in the literature.17 One issue that complicates the study of asphaltene precipitation is the kinetics of precipitation. Wang observed that the time required for a reasonable approximation to equilibrium for asphaltene precipitation with paraffin solvent at ambient temperature is on the order of 24 h.18 Solution formation is time-dependent, which is indicative of very slow kinetics in particle formation and reorganization.19 What additional studies are required? More studies on model systems to understand deposition? The approach presented by Broseta et al.20 and similar measurements performed in Norway21 and New Mexico9 indicate that oils that deposit in the field will also form (16) Qin, X.; Wang, P.; Sepehrnoori, K.; Pope, G. A. Modeling Asphaltene Precipitation in Reservoir Simulation. Ind. Eng. Chem. Res. 2000, 39, 2644-2654. (17) Mansoori, G. A. Asphaltene Deposition and its Control. Available via the Internet at http://tigger.uic.edu/∼mansoori/ Asphaltene.Deposition.and.Its.Control_html. (18) Wang, J. Predicting Asphaltene Flocculation in Crude Oils, Dissertation, New Mexico Institute of Mining and Technology, Socorro, NM, April 2000. (19) Anderson, S. I. The State of Asphaltenes in the Region we Called CMC!?. Presented at the Fourth International Conference on Phase Behavior and Fouling, Trondheim, Norway, June 2003. (20) Broseta, D.; Robin, M.; Savvidis, T.; Fe´jean, C.; Durandeau, M.; Zhou, H. Detection of Asphaltene Deposition by Capillary Flow Measurements. Presented at the SPE IOR Symposium, Tulsa, OK, April 3-5, 2001, SPE Paper No. 59294. (21) Fotland, P. (Norsk Hydro Research Center, Bergen, Norway). Personal communication.

deposits in steel capillaries when precipitation is induced with normal alkanes. Cornelisse et al.22 seemed to have been successful in producing asphaltene deposits from reservoir fluid samples at reservoir conditions. When Do Asphaltenes Precipitate and When Do They Deposit? Part of the problematic conventional wisdom regarding asphaltene deposition is depicted in Table 1, which shows data obtained from a popular website.14 A typical story is that the resins stabilize the asphaltenes in solution. Thus, the greater the resin-toasphaltene (R/A) ratio, the more stable the asphaltenes in solution. Sometimes that seems acceptable, but there are exceptions. For example, the Boscan crude (R/A ) 1.7) has no problems whereas the Tecoaminocan crude (R/A ) 5.9) has frequent deposition problems in the field. Sequential precipitation to collect different oil fractions is a frequently used technique. The schematic shown in Figure 15 was developed by researchers at the University of Michigan.23 The asphaltenes in solution are sequentially precipitated by increasing the paraffin content of the solvent beginning with dichloromethane. The schematic is shown in Figure 15. Table 2 shows the results of the Michigan work. The fraction most readily correlated with problem crudes, based on the abundance of this fraction in unstable crudes, is the 40:60 fraction. The fraction seems relatively large in both the deposit and in the unstable crude. However, when they compared an assay of the original oils to the field deposits, none of this fraction was present in the original oil! A more typical way of assessing the potential for field deposition and precipitation was presented by de Boer et al.24 These authors presented the supersaturation of the reservoir fluid for asphaltenes as a function of the (22) Cornelisse, P. M. W.; Flannery, M. B.; Zougari, M. I.; Hammami, A. Asphaltene Precipitation and Deposition Under Live Oil Conditions in a Novel Experimental Device. Presented at the Fourth International Conference on Phase Behavior and Fouling, Trondheim, Norway, June 2003. (23) Wattana, P. Ph.D. Dissertation, University of Michigan, Ann Arbor, MI, 2004. (b) Nalwaya, V.; Tangtayakom, V.; Piumsomboon, P.; Fogler, H. S. Studies on Asphaltenes through Analysis of Polar Fractions. Ind. Eng. Chem. Res. 1999, 38 (3), 964-972. (24) de Boer, R. B.; Leerlooyer, K.; Eigner, M. R. P.; van Bergen, A. R. D. Screening of Crude Oils for Asphalt Precipitation: Theory, Practice and the Selection of Inhibitors. SPE Prod. Facil. 1995, (February), 55-61.



Figure 15. Schematic depiction of the crude oil asphaltene separation.

Figure 16. Asphaltene instability in reservoir fluids as a function of density. Table 2. Composition by Sequential Precipitation: A Comparison of Asphaltene Problem and Nonproblem Oils

in situ density of the reservoir fluid and the degree of undersaturation, with respect to solution gas. This is shown in Figure 16. Cases of reservoir fluids with “bad field problems” are placed in the figure to correlate

supersaturation regions where reservoir fluids could cause problems. The difficulty with this approach is the relatively high number of false positives where precipitation occurs but field deposits are not formed.

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Figure 17. Precipitation of asphaltenes from a reservoir fluid: dotted line represents the solids detection system (SDS) trace, red line represents the stability limit, and the blue line represents the solubility limit.

Porte et al.25 determined a more general description of asphaltenes that attempts to honor the generally observed experimental phenomena. New Ideas for Asphaltenes. The most insoluble portion of an almost continuous spectrum are the different polyaromatic species, each of them having presumably its own couple of parameters da and (Ko/va)1/2. Aggregation and precipitation are distinct steps in a completely reversible process. Both are important. Aggregation proceeds from specific, strong interaction sites located at the periphery of the asphaltene molecules that drives the reversible association in twodimensional sheets, a morphology that is consistent with reported scattering and viscosity data. Precipitation eventually occurs, as determined by van der Waals attractions between aggregates. After taking all of this information into consideration, let us propose a general mechanism for arterial deposition based on observations regarding wax, asphaltenes, hydrates, and scale deposition. General Mechanism for Arterial Deposition of Asphaltenes in Flow Lines Based on my experience with deposition experiments and observations of the deposition of wax, asphaltenes, and hydrates, I suggest the following as a general mechanism for arterial deposition of material in pipelines: • Flow of fluid supersaturated with precipitating phase in flow line with turbulence, inducing precipitation along the wall (loss of supersaturation) • Pressure drop along the major axis of the well bore, as well as the temperature decrease responsible for causing supersaturated condition • The initially precipitated material along the wall is deposited as a “gel” layer, which ripens and becomes (25) Porte, G.; Zhou, H.; Lazzeri, V. Reversible Description of Asphaltene Colloidal Association and Precipitation. Langmuir 2003, 19, 40-47.

harder with time; the material often is observed in the dry deposit • For asphaltenes,

Freedom of Action in the State of Asphaltenes: Escape from

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