Article pubs.acs.org/EF
Asphaltene Deposition Jill S. Buckley* PRRC, New Mexico Tech, Socorro, New Mexico ABSTRACT: Although asphaltenes are always present in crude oils, they create problems only when they become insoluble in the remainder of the oil. A change in asphaltene solubility can occur because of changes in pressure, composition, or temperature. Whether asphaltene insolubility constitutes a problem, however, depends primarily on when and where in the oil production, transportation, and processing stream it occurs. Instability leading to deposition in a deepwater well is high on the list of potentially problematic situations. While insolubility is a necessary condition, it is not sufficient to predict the buildup of an asphaltene deposit in a production well. Flocculated asphaltenes may deposit or be carried out of the well in the flowing oil phase. To improve understanding and, hence, prediction of asphaltene deposition, several tests have been reported. A capillary deposition test in long stainless steel capillaries has been used to investigate the tendency of a wide variety of oils to create deposits. Observations, in addition to pressure increases during flow through a capillary, include changes in morphology of asphaltene flocs as they slowly separate from unstable oils, the amount of asphaltene produced as a function of time, and chemical analysis of deposits recovered from capillary tests. Other tests have used glass capillaries and a Taylor−Couette cell. As insight grows, the data produced are being used to develop simulators to predict the rate of growth of arterial asphaltene deposits under wellbore conditions.
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INTRODUCTION Asphaltenes can cause problems at almost any stage of oil production, transportation, or refining. Some problems can be avoided by ensuring that conditions of asphaltene instability are avoided. Others may be tolerated if treatment is relatively inexpensive. In deep offshore wells, avoiding instability may be impossible, and solutionswhether designed into wells and platforms or provided after a problem occursare likely to be extremely expensive.1 It is therefore important to be able to predict reliably when asphaltene problems will occur in such expensive wells. Progress in understanding asphaltene phase behavior and in predicting asphaltene problems has been slow, mainly because of the chemical complexity of crude oils’ heavy ends. According to Nellenstyne,2 asphaltenes were first described by Boussingault in 1837. They have been the subject of an enormous amount of research in many laboratories over the years since, yielding their secrets a little at a time. Understanding why some oils, often those with only small amounts of asphaltenes, produce arterial deposits in production wells while others do not has been particularly challenging. The first step was to improve characterization of asphaltene stability in their crude oil environment as a function of thermodynamic variables so that different oils can be compared under roughly equivalent conditions. One key to appropriate characterization was recognition that the onset of instability, not the amount of asphaltene separated by an excess of nonsolvent, is the variable of primary significance. Although it is true, as pointed out by Maqbool et al.,3 the onset of instability is not a single, well-defined point; nevertheless, some measure of instability that is relevant to the time scale of experiments and field experience is necessary. A growing awareness that the contributions to phase behavior of the rich mixture of middle components in the oil cannot be duplicated by simple mixtures of, for example, heptane and toluene has been another © 2012 American Chemical Society
important step. Finally, many entrenched misconceptions including pictures of asphaltenes as inverse micelles with polar centers, assumptions that there must be specific interactions between asphaltenes and a coating of peptizing resins, etc., have slowed progress. While there is undoubtedly much yet to learn about this chemically complex crude oil fraction, many researchers now accept the following views: • Stable asphaltenes exist in oil as nanoaggregates.4 • The microscopically visible phase separation has the appearance of a liquid−liquid separation below the glass transition temperature of the heavier phase.5 • Aggregation of the separated asphaltenes occurs because of van der Waals attractive forces, not polar interactions.6 Methods have been developed to characterize and to model asphaltene phase behavior. The earliest example of experimental onset characterization is the Oliensis spot test.7 The ASIST method8 uses microscopic observations to identify asphaltene instability in response to changes in oil solubility parameter. Measurements for a range of n-alkanes can be used to predict onsets that would occur due to the presence of light ends, lift gases, etc. either directly or by using as input for asphaltene characterization in models.9,10 An application to a deep water field in the Gulf of Mexico was presented by Montesi et al.11 Once the onset conditions have been established, some problems can be resolved by controlling thermodynamic variables to avoid asphaltene phase separation (e.g., Abdallah et al.12). In production wells, however, the problem conditions are not so easily avoided. However, while asphaltenes must be Special Issue: Upstream Engineering and Flow Assurance (UEFA) Received: February 14, 2012 Revised: June 8, 2012 Published: June 11, 2012 4086
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Table 1. Summary of Asphaltene Deposition Testing Methods geometry
materials
dimensions
vol.
capillary-circular capillary-circular capillary-circular
SS 316 SS 316 SS
PV = 0.74 mL PV = 6.3 mL PV = 2−7 μL
injection at 3 mL/min, 2 oils, no deposit below onset low shear rate, compare 3 oils and 3 precipitants two critical shear rates that depend on solvent qualitya
Broseta 200016 Wang 200417 Nabzar 200818
dapillaryrectangular
glass
0.25 mm ID × 15 m 0.5 mm ID × 32 m 0.065−0.133 mm ID × 50 cm 600 μm × 150 μm × 100 mm
PV = 9 μL
pressure drop and imaging redissolved asphaltenes
Boek 200819
PV = 71 mL
whole oil diluted with toluene temp. at the wall is higher than in bulk fluid, fluids are premixed
Boek 201020 Jamialahmadi 200921
PV ∼ 150 mL
vary flow rate, dT, and pentane vol. amount of deposit calcd from meas. of thermal conductivity and heat transfer coefficient batch
∼1 L/run
flow through
pipe-circular
Taylor−Couette cell
SS
SSb
23.8 mm ID × 160 mm
ro = 2ri
notes
ref
Zougari 200622 Akbarzadeh 200923
a Below lower critical shear rate, deposition is diffusion limited; above higher critical shear rate, deposition is shear limited. bCell is stainless steel, but surface can be any material from which a sleeve can be made.
Capillary Tests. Brosetta et al.16 developed the asphaltene capillary deposition test and established clearly that deposition occurs only when asphaltenes are unstable. Comparisons of mixtures of identical amounts of oil with varying ratios of heptanes and xylene flowed through long stainless steel capillary tubes with unchanging pressure drop until the mixture contained sufficient heptanes to destabilize asphaltenes. In tests with 100 ft long stainless steel capillaries at low shear rates, Wang et al.17 reported creation of more deposit with higher molecular weight nonsolvents (e.g., n-pentadecane) than with lower molecular weight nonsolvents (e.g., n-heptane) for two crude oils. This result was unexpected because tests of the amount of asphaltene precipitated by nonsolvents always show amounts increasing as the molecular weight of the nonsolvent decreases and subsequent tests with other oils have sometimes shown the opposite trend. Some dead oil samples contained preformed asphaltene flocs. These existing asphaltenes did not deposit; they were propagated through the capillary with the oil. It was necessary to destabilize the asphaltenes by mixing with nonsolvent immediately upstream of the capillary to cause arterial deposition to occur in these tests. This evidence suggested that there might be a stage in asphaltene phase separation and floc growth that is optimum for the tendency to form an arterial deposit. For modeling these results, Vargas et al.24 assume that there is a competition for the initially formed small particles; they can either join flocs that propagate through the tube or join the growing arterial deposit. Only at the initial stage when particles are small are they potentially available to form deposit. Nabzar et al.18 explored a wide range of shear rates in stainless steel capillary tubes. They demonstrated that there are two critical shear rates that affect deposit formation: an upper critical shear rate limits growth of the deposit, whereas a lower critical shear rate marks a change from a region dominated by diffusion limited aggregation (DLA) (c.f., Yudin et al.25) at low shear rates to one in which deposit grows by DLA and is eroded by shear forces at intermediate shear rates. Glass capillaries have the added advantage that the process can be imaged, not just evaluated from pressure drop as a function of time. Boek et al. 19,20 have demonstrated destabilization of asphaltenes from toluene solutions and from toluene diluted crude oil and have used a combination of colloidal and molecular models to evaluate the results.
unstable to cause deposition, not all unstable asphaltenes cause impairment of producing wells. Asphaltene aggregates may be produced with the flowing oil and only be noticed downstream in separators, etc. The de Boer plot13 has long been used to predict which cases are more likely to create arterial deposits, however de Boer plot criteria can produce many false positives.14 If it could be reliably established during project design that arterial depositionthat is, growth of an asphaltene-rich deposit on pipe walls of the type first described in the HassiMessaoud field15is likely, remedial measures can be included in the design and costs associated with intervention after the fact can be avoided. If, on the other hand, deposition is not likely, the costs of those remedial elements can be eliminated from the design. Experimental and modeling advances are moving us toward the day when these difficult questions may be answered with reasonable reliability.
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ARTERIAL DEPOSITION OF ASPHALTENES
Tests of asphaltene deposition have been conducted primarily in two geometries: tubes of capillary16−20 or larger21 dimensions and Taylor−Couette (TC) cells.22,23 Table 1 summarizes selected literature on experimental asphaltene deposition testing. Long capillary tubes, mainly of stainless steel, allow pressure measurements in a high surface area, low volume environment. Glass capillaries have the advantage that images can demonstrate accumulation of deposit and particles can be distinguished, if large enough. In tests with larger tubes wall temperatures were higher than the bulk temperature of the destabilized oil. This study is included in Table 1 for completeness, but it is not directly comparable to the other isothermal tests and is therefore not treated in the following discussion. The TC cell can be operated at reservoir conditions of temperature, pressure, and composition. Shear rate can be varied by changing flow rate and diameter in capillaries and by controlling rotational speed in the TC cell. The TC cell requires about 150 mL of sample in batch mode and on the order of 1 L in the flow though operation often required to demonstrate asphaltene deposition. Capillaries require smaller amounts of sample and can be run for longer periods of time, until plugging or sample limitations are encountered. Capillary and TC approaches were compared by Montesi et al.11 4087
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Figure 1. Mixtures of oil A and n-C15 aged in microtubes at 50 °C (tubes are 200 μm across).
Table 2. Summary of Crude Oil Properties (mg KOH/g oil) oil
API gravity (deg)
μ (cP) at 20 °C
AN
BN
saturates
aromatics
resins
n-C6 asph.
A B C
29.9 34.5 33.9
23.1 7.5 7.8
0.24 0.06 0.01
1.58 1.31 1.22
52.3 62.9 74.3
20.8 21.4 16.7
20.7 13.3 7.6
6.2 2.4 1.4
Taylor−Couette Cell Tests. Initial batch-mode tests in the TC cell established that both wax and asphaltene deposits could be detected,22 but amounts of asphaltene deposit were small, and deposit formation reached a plateau as a function of time. No effect of wall vs bulk temperature, analogous to wax deposition, was observed. Subsequent work has shown that supplying fresh sample during the course of a test in flowthrough mode produces larger amounts of asphaltene deposit.23 A particularly interesting result showed that the oil in a batchmode test is not, in fact, depleted of deposit forming material. If it is restored to reservoir conditions and reused in batch-mode, deposit again forms in response to decreasing the pressure. The deposit forming tendency of the reused oil is similar to its initial response. Particles growing into and then beyond some critical size range would show this behavior and a critical size has been used to model these results. Sizes in the micrometer range were expected, but sizes in the tens of nanometers better fitted their results. In all of the tests reviewed above, particles in the colloidal size range appear to play a key role in determining the tendency for asphaltenes to produce a deposit. Nanoaggregates that are stable in crude oils did not deposit, nor do large flocs. There is a size window, and thus a time window, through which aggregate growth may pass rapidly or slowly. Presumably, the question of whether an oil will cause arterial deposition problems can best be answered by knowing where and when that window will be open. Thus, kinetics of asphaltene aggregate growth appear to be a key issue.
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(wt %)
examined the results of light scattering experiments and found that the pressure step where absorbance begins to increase rapidly is at a pressure well beyond the first appearance of asphaltenes. Slow kinetics near the onset cause only subtle changes in absorbance. Maqbool et al.3 showed that onset observations depend mainly on the patience of the observer, with slow changes continuing over several months or more. Yudin et al.25 used photon correlation spectroscopy to follow asphaltene aggregation. As the amount of nonsolvent increased, aggregation proceeded more rapidly, changing from reactionlimited to diffusion-limited aggregation. Mason and Lin29 used a small angle neutron scattering (SANS) technique to observe particle growth in mixtures of incompatible oils. They noted that mixture viscosities were a necessary parameter for fitting the data to a colloidal model. Khoshandam and Alamdari30 followed aggregation of particles from 1 nm to 6 μm with dynamic laser light scattering. Of these three studies, only Mason and Lin29 demonstrated the capability to measure the growth of particles in oil, however. Using redissolved asphaltenes in heptanes and toluene mixtures may be misleading with regard to aggregation mechanisms and would not be applicable to making predictions for field conditions. Maqbool et al.31 investigated the effects of temperature on aggregation rate, concluding that raising the temperature makes the oil a better solvent, reducing the amount of asphaltene produced. Making the oil a better solvent should have the effect of slowing the rate of aggregation, but at the same time, viscosity is reduced, which has the opposite effect on aggregation rate, and the net effect is a combination of these two contributions, assuming the temperature is not so high as to cause coking reactions and no evaporation occurs. Imaging of Asphaltene Aggregation. In order to track floc growth to provide input on kinetics for modeling purposes, we imaged mixtures of crude oils mixed with nonsolvents as a function of time since initial mixing. Times ranged from a few minutes to days or weeks. Micrographs provide qualitative information, limited to sizes of about 0.5 μm and larger. Whether this captures the relevant particle size range is not certain, but some interesting and unexpected observations have resulted from these studies. Two methodologies have been used:
KINETICS OF ASPHALTENE AGGREGATE GROWTH
Kinetics of asphaltene precipitation and floc growth can vary depending on many factors. Near the onset of instability, kinetics can be very slow, leading to differences in results of tests that are conducted over different time intervals, as illustrated by Hotier and Robin.26 Continuous titration tests overestimated the stability of asphaltenes in solvent/nonsolvent mixtures when the titration rate was high compared to the same tests performed at slower rates. Wang27 identified onset mixtures of crude oil and several different nonsolvents as a function of time since initial mixing. In the first few hours there were major differences in observations over short increments of time. After a day or two, the changes are much slower, but changes could still be discerned after two weeks. Correra et al.28
• Oil was mixed with nonsolvent and stored in a closed vial from which samples were removed at the times indicated. 4088
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In most cases the sample was observed and photographed between a glass slide with a glass coverslip. Such observations must be made quickly since the removed sample will experience changes due to evaporation. • After mixing oil and nonsolvent, a glass capillary tube (50 mm in length by 200 μm across by 20 μm deep) was filled with the mixture and the ends were sealed with epoxy. Micrographs were taken through the glass capillary as a function of time. Examples of clearly stable and unstable mixtures are shown in Figure 1. Three crude oils (depressurized samples) for which asphaltene field problems have been reported were observed after mixing with nonsolvents. Oil properties are summarized in Table 2. The first oil tested by this method was oil B. Near onset conditions, a haze of fine particles gradually appeared over the first 20−30 min, as shown in Figures 2 and 3 at 25° and 70 °C,
Figure 3. Oil B mixed with n-C7 (75:25) and aged at 70 °C.
Figure 4 where destabilized samples, aged for 12 h in bulk (Figure 4a) and for the same period in the capillary (Figure 4b) are compared. The sample aged in bulk solution was transferred to a capillary to produce the image in Figure 4a. It was then allowed to age in the capillary for an additional 12 h, producing the chain-like results shown in Figure 4c. Although the chainlike structures, once formed, move very little in successive images, they do not appear to be attached to the glass and can be moved. Whether they form in response to confinement or because of asphaltene-surface interactions is not clear. Oil B is the only sample examined to date that shows this confined growth phenomenon at near onset conditions. The other two samples, oils A and C, can make extended structures, as shown in Figure 1 for oil A at very unstable conditions. However, near the onset, only small particles appear. Asphaltenes from these oils precipitate very rapidly, appearing in the first photos taken at 5 min after mixing and do not appear to increase in number or to grow into larger structures with time, even in the confinement of the capillary tube. While this is disappointing from the standpoint of measuring the kinetics of aggregation, it may be a clue to why these two oils produce asphaltene deposits, since a population of small particles should favor deposition. Further investigation with problematic and nonproblematic oils is needed to confirm these observations.
Figure 2. Oil B mixed with n-C7 (75:25) and aged at 25 °C.
respectively. Gradually, the particles joined together to make chain-like structures. At higher temperature, the process was slightly faster and less asphaltene separated from the oil, consistent with the observations reported by Maqbool et al.3 It appeared that this sequence of images would be amenable to the use of image analysis to produce kinetic information needed by models. However, further investigation showed that the chain-like structures formed only in the capillary tube. Samples aged in bulk were quite different in appearance, as shown in
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DISCUSSION The different deposition tests discussed have different strengths and limitations, but all point to the importance of colloidalsized asphaltene particles in producing arterial deposits. One comparison of capillary and TC cell tests showed that both were somewhat helpful in predicting deposition rates, but cost 4089
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Figure 4. Mixtures of oil B and n-C7 (80: 20), aged at 25 °C (each photo is an area of 50 μm × 100 μm). (8) Buckley, J. S.; Wang, J. X.; Creek, J. L. In Asphaltenes, Heavy Oils, and Petroleomics; Mullins, O., Sheu, E., Hammami, A. , Marshall, A., Eds.; Springer: New York, 2007; pp 401−437. (9) Ting, P. D.; Gonzalez, D. L.; Hirasaki, G. J.; Chapman, W. G. In Asphaltenes, Heavy Oils, and Petroleomics; Mullins, O., Sheu, E., Hammami, A., Marshall, A., Eds.; Springer: New York, 2007, pp 295− 322. (10) Vargas, F. M.; Gonzalez, D. L.; Hirasaki, G. J.; Chapman, W. G. Energy Fuels 2009, 23, 1140−1146. (11) Montesi, A.; Pinnick, R.; Subramanian, S.; Wang, J.; Creek, J. Paper OTC 21587. 2011 OTC, Houston, TX, May 2−5, 2011. (12) Abdallah, D.; Al-Basry, A.; Zwolle, S.; Grutters, M.; Huo, Z.; Stankiewicz, A. Paper SPE 138039. 2010 ADIPEC, Abu Dhabi, Nov 1− 4, 2010. (13) de Boer, R. B.; Leerlooyer, K.; Eigner, M. R. P.; van Bergen, A. R. D. SPE PF 1995, 10 (Feb.), 55−61. (14) Wang, J. X.; Creek, J. L.; Buckley, J. S. Paper SPE 103137. 2006 ATCE, San Antonio, Sept. 24−27, 2006 (15) Haskett, C. E.; Tartera, M. JPT 1965, 17 (April), 387−391. (16) Broseta, D.; Robin, M.; Savvidis, T.; Féjean, C.; Durandeau, M.; Zhou, H. Paper SPE 59294. 2000 IOR Symp., Tulsa, April 3−5, 2000. (17) Wang, J. X.; Buckley, J. S.; Creek, J. L. J. Dispersion Sci. Technol. 2004, 25, 287−298. (18) Nabzar, L.; Aguiléra, M. E. Rev. IFP 2008, 63, 21−35. (19) Boek, E. S.; Ladva, H. K.; Crawshaw, J. P.; Padding, J. T. Energy Fuels 2008, 22, 805−813. (20) Boek, E. S.; Wilson, A. D.; Padding, J. T.; Headen, T. F.; Crawshaw, J. P. Energy Fuels 2010, 24, 2361−2368. (21) Jamialahmadi, M.; Soltani, B.; Muller-Steinhagen, H.; Rashtchian, D. Int. J. Heat Mass Transfer 2009, 52, 4624−4634. (22) Zougari, M.; Jacobs, S.; Ratulowski, J.; Hammami, A.; Broze, G.; Flannery, M.; Stankiewicz, A.; Karan, K. Energy Fuels 2006, 20, 1656− 1663. (23) Akbarzadeh, K.; Ratulowski, J.; Lindvig, T.; Davies, T.; Huo, Z.; Broze, G.; Howe, R.; Lagers, K. Paper SPE 124956-PP. 2009 ATCE, New Orleans, Oct. 4−7, 2009. (24) Vargas, F. M.; Creek, J. L.; Chapman, W. G. Energy Fuels 2010, 24, 2294−2299. (25) Yudin, I. K.; Nikolaenko, G. L.; Gorodetsky, E. E.; Kosov, V. I.; Melikyan, V. R.; Markhashov, E. L.; Frot, D.; Brioland, Y. J. Pet. Sci. Eng. 1998, 20, 297−301. (26) Hotier, G.; Robin, M. Rev. l’IFP 1983, 38, 101−120. (27) Wang, J. X. PhD Thesis, NMIMT, Socorro, April, 2000. (28) Correra, S.; Capuano, F.; Panariti, N. 5th International Conference on Petroleum Phase Behaviour and Fouling, Banff, June 13−17, 2004. (29) Mason, T. G.; Lin, M. Y. J. Chem. Phys. 2003, 119, 565−571. (30) Khoshandam, A.; Alamdari, A. Energy Fuels 2010, 24, 1917− 1924. (31) Maqbool, T.; Srikiratiwong, P.; Fogler, H. S. Energy Fuels 2011, 25, 694−700. (32) Maqbool, T.; Raha, S.; Hoepfner, M. P.; Fogler, H. S. Energy Fuels 2011, 25, 1585−1596. (33) Eskin, D.; Ratulowski, J.; Akbarzadeh, K.; Pan, S. Can. J. Chem. Eng. 2011, 89, 421−441. (34) Kurup, A. S.; Vargas, F. M.; Wang, J. X.; Buckley, J.; Creek, J. L.; Hariprasad, J. S.; Chapman, W. G. Energy Fuels 2011, 25, 4506−4516.
comparison favors the use of the less expensive capillary test that is not run at reservoir conditions.11 The identification of particle size and the importance of the kinetics of aggregate growth help to explain the observation of deBoer et al.13 that light oils with less than 0.5% asphaltenes are likely to produce deposits. First, these oils are poor asphaltene solvents, likely to produce conditions of instability. Beyond that, however, having low viscosity may increase the rate at which asphaltene particles appear, whereas being few in number may limit the growth of larger flocs, optimizing the opportunity for arterial deposits to form. Models that incorporate the importance of particle size have been successful in reproducing the behavior observed in deposition tests.18,20,23,24,32 Application of these models to predictions of deposition in a pipeline has been reported.33 The wellbore simulation presented by Vargas et al.24 has been extended34 and shown to correctly predict a set of field observations. Input on kinetics of aggregate growth has thus far mainly been provided by quantitative measurements of the weight of centrifuged particles as a function of time. Methods that track particle growth (e.g., refs 25, 29, and 30) are needed, but they must be adapted to largely undiluted crude oils as the results of tests using redissolved asphaltenes or highly diluted crude are not predictive of what can be expected in the field.
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AUTHOR INFORMATION
Corresponding Author
*Email:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS Capillary deposition testing at New Mexico Tech has been supported by the DeepStar Consortium. Many colleagues have contributed to this effort including Jeff Creek and Jianxin Wang of Chevron, George Hirasaki and Walter Chapman (and their groups) at Rice University, and Tianguang Fan of New Mexico Tech.
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REFERENCES
(1) Creek, J. L. Energy Fuels 2005, 19, 1212−1224. (2) Nellensteyn, F. I. J. Inst. Pet. Technol. 1924, 10, 211. (3) Maqbool, T.; Balgoa, A. T.; Fogler, H. S. Energy Fuels 2009, 21, 3681−3686. (4) Andreatta, G.; Goncalves, C. C.; Buffin, G.; Bostrom, N.; Quintella, C. M.; Arteaga-Larios, F.; Perez, E.; Mullins, O. C. Energy Fuels 2005, 19, 1282−1289. (5) Sirota, E. B. Energy Fuels 2005, 19, 1290−1296. (6) Buckley, J. S.; Hirasaki, G. J.; Liu, Y.; Von Drasek, S.; Wang, J. X.; Gill, B. S. Petroleum Sci. Tech. 1998, 16, 251−285. (7) Oliensis, G. L. ASTM, Proc. of the 36th Ann. Meeting; Chicago, June 26−20, 1933; Vol. 33, Part II, pp 715−728. 4090
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