Method and Device for Quantitative Measurement of Crude Oil Fouling

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Method and Device for Quantitative Measurement of Crude Oil Fouling Deposits of Several Crude Oils and Blends at a Higher Temperature and the Impact of Antifoulant Additives Yassin Al Obaidi, Mike Kozminski, and Joshua Ward Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b01406 • Publication Date (Web): 11 May 2018 Downloaded from http://pubs.acs.org on May 13, 2018

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Method and Device for Quantitative Measurement of Crude Oil Fouling Deposits of Several Crude Oils and Blends at a Higher Temperature and the Impact of Antifoulant Additives Yassin Al Obaidi,* Mike Kozminski, Joshua D. Ward American Refining Group, Inc. 77 North Kendall Avenue, Bradford, PA 16701

Since the establishment of crude oil refining, refiners have encountered the problem of fouling in heat exchanger trains, heaters, and atmospheric and vacuum distillation columns. Crude oil fouling is one of the major problems that triggers efficiency reduction, environmental impact, unplanned shutdown, and loss of revenue and yield. In the topic of crude oil fouling, most published papers were focused on heat exchanger fouling and to a lesser extent, on the distillation columns and heaters. However, with the absence of a vacuum column, some small refineries operate and flash the crude oil at or above 700°F for better recovery. In this study, a simple and affordable bench-type research laboratory rig was fabricated and used for the determination of the gravimetric fouling deposits for several crudes and blends at an elevated temperature of 720°F or more. To address the high temperature impact on crude oil fouling, the ∆ API and ∆ microcarbon were used to indicate the extent of the thermal cracking. UV-Visible 1 ACS Paragon Plus Environment

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spectroscopy was utilized to detect the increased aromaticity of agglomerated asphaltenes and resins due to possible self-association at higher temperatures. At a higher temperature, the thermal cracking is much greater than that at 580-620˚F and the fouling could take on different mechanisms.

1. Introduction Crude oil fouling in the preheat exchangers, crude unit heaters, and distillation columns is causing significant economic and operating cost penalties. Handling crude oil fouling has been a great challenge in all refineries all over the world. In general, fouling is responsible for increasing the cost of processing crude oil and the maintenance. Also, it is limiting the flexibility of processing different types of crude oils. Van Nostrand, 1 in 1981, published his article about the penalties associated with crude oil fouling in the USA. The total cost of fouling in US refineries was estimated at 1.36 billion a year. Preheat train exchanger fouling has received most of the attention of crude oil fouling research and projects.

2,3,4

The 2001 study by Yeap et al5 in

United Kingdom showed that if a preheat train processing 100,000 bpd experienced a drop of 1000 bpd, it would cause almost ₤25,000 of added fuel cost and 750 tons of additional CO2 emission each year. Kister, 6 in his 1990 and 1997 surveys, found that the number of malfunctions rose by 5-fold for the period of 8 years (1990-1997) compared to a period of 40-50 years between (1950 and 1989). Furthermore, Kister, 7 in his last review reported an additional 300 case studies of fouling and malfunctions of refinery towers such as plugging of trays and coking for the last five years before publishing his paper in 2003. Due to a shortage of light sweet crude oil, and to overcome the cost of crude oil, many refineries were forced to buy different qualities of crude oil to keep their throughput and to 2 ACS Paragon Plus Environment

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maximize profitability. The blending of different crude oils has introduced new and significant types of fouling due to crude oil blending incompatibility. The blending incompatibility can be simply defined as the propensity of deposit formation through the mixing of two or more crude oils. Irwin A. Wiehe and R.J. Kennedy8,9 in 2000 introduced the idea of solubility parameters of the insolubility number IN and the solubility blending number SBN. Both of these numbers can then measure the asphaltene aggregation and precipitation from the crude oil blending. Several studies 10,11,12 have also discussed crude oil blending compatibility and fouling. Meanwhile, tight or shell crude oils are adding new and different challenges for refiners using them. EIA13 in 2016 estimated the production of tight oil above 4 million barrels per day. Although tight oils are considered opportunity crude (less expensive) these crudes, and especially the light tight crude oils, have different types of compositions such as high waxy paraffins, filterable solids, and composition variability. The nature of their light paraffins can cause the destabilization of asphaltenes when blending with other types of crude oils. Recently, many articles

14,15,16

have discussed the fouling problems of tight oil in the crude desalter, heat

exchangers, furnaces, and distillation columns. Most of the studies on the complex real crude oil fouling in the crude unit were focused on heat exchanger fouling. Data generated from actual plants are slow and subject to many uncontrolled variables

17

. Several methods and devices were designed and used for the study of

crude oil fouling such as hotwires, microbomb reactors, batch stirred cells, and flow loops

18

.

Recently, the lab scale closed liquid system microbomb was used by Rostani19 to study the effect of vanadium on crude oil heat exchanger fouling. Additionally, many large scale devices were used to study crude oil fouling such as the stirred cell at the University of Bath

20

and the Heat

Transfer Research Inc. (HTRI) HTFU annular reactor with a crude charge of 30 liters

21

. Ratel

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M. and et al22 have use a pilot plant consisting of five closed loops to mimic real refinery operations for their study of fouling rates in heat exchangers. 2. Experimental

2.1. Building the Fouling Rig. The crude oil fouling rig illustrated in Figure 1 was designed in-house and built by a commercial company. The whole unit was built from stainless steel except for the test reactor, which was carbon steel. The rig’s main sections are as follows: a) A 2.2 L crude oil vessel equipped with tape heater, filling valve V1, drain valve V2, and temperature gauge T1. N2 gas is charged into the unit from a tank connected by a valve. b) Three sections of ¼” pipes heated with three tape heaters and controlled by three thermocouples TC1, TC2, and TC3. c) A circulating pump with controlled volume delivery capability located immediately after heated section one. Pressure gauge P1 and drain valve V3 are connected to the pump assembly; V3 is at the lowest point for easy draining. d) The test reactor, which was made from carbon steel to emulate the refinery columns and heaters with 15” length and ¾ ” OD and a total capacity of 68 mL. The reactor was bracketed with two valves, V4 and V5, and two temperature gauges, T2 and T3. The fouling section is heated with a 12” cylindrical 600 w split ceramic heater. e) A cooling section with a second pressure gauge P2. This section was removed as it was not necessary. The P2 gauge was connected to the circulation line. f) A relief valve with outside discharge. g) A flowmeter can be added if the pump is not equipped with a metering device.


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Figure 1. In-house design of crude oil fouling testing rig. 2.2. Principles of the Crude Oil Fouling Testing. The crude oil was topped at 400°F to reduce the flashing material but also to emulate the behavior of crude oil in the refinery heat exchangers and distillation columns. The principle of measuring crude oil fouling using the laboratory testing rig is to weigh and determine the amount of gravimetric deposited coke after a specific time of testing. One pass of the crude oil in a small reactor will never reflect the real retention time of the crude oil in the refinery’s heat exchanger and distillation columns. Due to the effect of the induction period, it is necessary to make the test longer. For these reasons, the design of this experiment was done with a continuous circulation of the crude oil. The size of the reactor is 68cc and the circulation will allow the formation of velocity turbulences. The reactor


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wall temperature is set at 740°F to simulate the refinery crude oil flashing temperature at 720°F and above. 2.3. Crude Oil Fouling Rig Procedure. The crude to be tested was either obtained from the refinery after the desalter or washed in lab; this way, the tested crude will emulate real refinery conditions. Additionally, this unit was kept at a constant pressure of 100 psi to keep the oil in liquid phase (bubble point is 773.8°F) so damage to the pump and gauges would be avoided. A new test reactor was first cleaned inside and out with toluene and wiping, then with pentane. It was dried in an oven at 105°C for one hour. After cooling, its weight was obtained. The test reactor was then installed into the unit with a split heater around it and heat insulation was added. The reservoir was filled with 1100 mL of crude then pressurized to 100 psi. The laboratory fouling rig test ran continuously for 20 hours with the reactor wall temperature at 740°F. The crude oil from the unit was drained using valve V3 and retained. The reactor along with V4 and V5 was removed and hung vertically to drain into a beaker. Then, in a separate beaker, the reactor was rinsed out with pentane and collected to remove any remaining crude; however, some coke will fall and need to be filtered and weighed. After being dried at 105°C for 1 hour, the reactor was cooled to room temperature and its weight was recorded. The pentane wash from the reactor was filtered via a modified ASTM D4807-88 method. The weight of the filterable solids from this was added to the coke from the reactor to get the total weight of the formed coke. 3. Result and Discussion 3.1 Coke Formation and Measurement. This paper mostly discusses thermal chemical cracking, asphaltene destabilization, and to a lesser extent, filterable particulate and inorganic fouling factors. This experiment does not utilize steam and therefore does not exhibit the 6 ACS Paragon Plus Environment

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negative impact of corrosion that is often considered as a fouling material in real refinery operations. Additionally, this experiment measures the propensity of fouling rather than the rate. This research was performed for a small refinery that was built to process the local light, sweet, and very low in asphaltenes crude oil. Due to a supply shortage of the local crude, the refinery is procuring different crude oils from varying qualities and formations. As mentioned above, the flash temperature at the atmospheric unit is around 720°F because there is no vacuum unit at the refinery. Four different crude oils A-D and two blend compositions, all topped to 400°F, were tested using the fouling rig. The wall temperature of the fouling reactor was kept at 740°F as each crude cycled through the continuous loop unit for a total of 20 hours, not including start-up time. As previously mentioned in the procedure section, the amount of coke formed was determined from the gravimetric difference of the reactor weight before and after the experiment including any residue found in the oil on the reactor. A full run was tested on an empty reactor to see how possible oxidation might affect the reactor weight; the resulting weight difference was very little. Some of the crude oil physical properties (before testing) and results, before and after the fouling test, such as carbon residue (micro carbon) %, amount of coke formed, and ∆ API are presented in Table 1 and Figure 2. The current Crude A composite is a blend of several local crude oils and in this research, was considered as the control crude. It was tested twice and the results, 253mg and 283mg respectively, were averaged in order to determine the repeatability and precision of the method. The precision ratio of Trial 1/Trial 2 of Crude A is about 90%. The average amount of total coke measured for Crude A was 268 mg. Table 1. Physical Properties and Results of Crude Oil Tested with Laboratory Fouling Rig


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Physical Properties of Crude Before Test Results Crude Oil Micro carbon Sulfur Total Coke Δ Micro carbon API Gravity Asphaltene SBN In Δ API % % wt%* (mg) % @ 60°F A composite avg. 34.69 0.070 15.0 0 0.591 0.0609 268 1.38 0.014 B 40.70 0 3.2 0 0 0.0200 85 0.79 0.022 80 A/ 20 B 35.77 0.498 307 2.32 0.019 50 A/ 50 B 37.62 0.216 252 2.10 0.100 C 34.38 0.003 14.0 0 0.458 0.0910 300 2.44 0.117 D 34.51 0.030 15.0 0 0.654 0.0590 359 2.25 0.116

* Average

Figure 2. Total coke (mg), ∆ API, and micro carbon % of crude after laboratory fouling. Because of the thermal impact factor in this work, measuring the API gravity before and after testing might indicate the extent of thermal cracking and its correlation to the coke formation. Similarly, micro carbon % values for before and after were measured and a correlation between fouling and micro carbon data were observed (Figure 2). More data and discussions are presented in sections 3.2 and 3.3 of this paper. The Solubility blending numbers (SBN) and the Insolubility blending numbers (IN) of Crude BD are listed in Table 1 and were compared to the control Crude A. The (IN) values for Crude B-D 8 ACS Paragon Plus Environment

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were zero which indicated a good blending compatibility with Crude A. Crude B in reality is a heavy paraffinic condensate produced by fracking drilling and as such, has zero asphaltenes and very low sulfur content. Due to this paraffinic nature, Crude B has a low (SBN) value and is more thermally stable at a higher temperature than Crude A. Crude B produced less amount of coke as indicated in Table 1. As expected, and from the SBN (Equation 1 below), blending 20% of Crude B with Crude A has increased the coke formation due to the lowering of the SBN. Although Crude A has very low asphaltenes, Crude B can destabilized the asphaltenes and big resin molecules which then increases the coke formation. Equation 1 is still applicable for the 50:50 blend of A:B but the reduced thermal cracking of the stable Crude B is going to be the most predominate factor, and thus the coking is decreased.

Equation 1. V denotes volume % and SBN is the Solubility Blending Number of the crude Crude C and D were different local crude oils with properties comparable to control Crude A. The resin content of Crude C was 7.33% compared to 2.70% of Crude D. Considering the Colloidal Instability Index (CII) (Equation 2), it is believed that the elevated resin content gave more solvation for the asphaltenes and because of that, Crude D formed more coke than Crude C. The C.I.I. number expresses the relative tendency for a crude oil to foul with a higher number indicating more susceptibility.

. .

Resin Aromatics

Equation 2. Colloidal Instability Index of crude oil.


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3.2 Thermal Cracking. The primary focus of this paper is to discuss the undesirable effects that occur when crude oil is heated beyond 680°F, specifically, thermal cracking. When thermal cracking occurs, a myriad of reactions take place. Large molar mass hydrocarbons, such as long paraffins and paraffins attached to resins and asphaltenes, are broken down into lighter alkane and alkene hydrocarbons. The increased API, seen in Table 1, supports this observation. However, alkenes are in a position to undergo autoxidation or polymerization18 as presented in Scheme 1. Most of these reactions involve free radicals and possible oligomerization. Polymerized material could act as the glue for adhering small coke particles to the wall of heater tubes and towers. As a summary, crude oil incompatibility, thermal cracking, and asphaltene destabilization and precipitation cause several complex chemical reactions to occur and ultimately

promote

fouling.

Scheme 1. Series of degradation reactions proposed by Eaton and Lux23. Most of the tested crude in this paper had minimal asphaltenes, so the majority of fouling would be from thermal cracking and the formation of olefins, and the resulting initiation of olefin polymerization and formation of larger aromatic molecules. Crude B, being a tight oil (condensate), is stable against thermal cracking as it lacks the heavier large aromatic molecules present in traditional crude. Due to thermal cracking, the refinery is experiencing severe fouling, especially at the bottom of the atmospheric distillation tower close to the flashing zone (Picture 1).


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Picture 1. Coke formed at the distillation tower above the flashing zone. An increase in polycyclic aromatic hydrocarbons, such as possible aggregated resins, have been observed in the tested crude oil. In the literature, UV-Vis spectroscopy was used for crude oil studies.24 Some published articles,25-27 suggested that asphaltene self-association and polymerization occurs during deposit formation while in another paper, aggregation of asphaltene with resin molecules in crude oils were also observed. In this work, UV-Vis spectroscopy was utilized to indicate possible resin-asphaltene and resin-resin associations. UVVis spectra of Figures 3 and 4 demonstrate that a shift to a longer wavelength and higher intensity likely indicates more, and newly formed polyaromatic molecules. In Figure 4, the absorbance of the 80/20 blend of Crude A/Crude B after testing is greater than that of the 50/50 blend. This is consistent with the amount of deposited coke as listed in Table 1 and Figure 2; the 80/20 blend formed more coke than the 50/50 blend. Not all of the formed coke would be adhered to the reactor wall; some will be suspended in the crude. The slight increase in micro carbon %, as displayed in Table 1, provides some supporting evidence of this and indicates the possible correlation between the coking tendency and micro carbon %.


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Figure 3. UV-Vis spectra of Crude A

Figure 4. UV-Vis spectra of 50/50 Crude A/

before and after laboratory fouling test.

Crude B before and after laboratory fouling

test compared to the 80/20 blend. 3.3 Measuring Fouling of Crude Oil with Antifouling Additives. Most crude oil antifoulant additives have been designed for refineries that flash at temperatures below 720°F. From Figure 5, the elevated temperatures of an atmospheric tower ironically seem to cause some commercial crude oil antifoulants to create more fouling rather than reduce it. Antifoulant α created 22.4% more coke with 300 ppm and 42.5% more with 1000 ppm compared to Crude Oil A without any antifoulants. Antifoulant β only created 5.2% more coke with 100 ppm. These additives may contain metal or metal oxides that, at a high temperature, increase cracking which leads to more coke formation and a lighter crude density. As seen in Figure 5, the slight increase in ∆ micro carbon % as well as the increased ∆ API supports the observation of increased thermal cracking. Moreover, the data does suggest that, within this high temperature experiment, no antifoulant additive is best. However, if antifoulants are to be used, the trend showed that a lower treatment rate is preferable. From this data, the refinery decided to use 100, 50, then 12 ACS Paragon Plus Environment

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35ppm of antifoulant additive α and produced better heat exchanger efficiency and less fouling by applying only 35ppm.

Figure 5. Total Coke (mg), ∆ API, and ∆ micro carbon % of Crude A with varying degrees of antifoulant additives after laboratory fouling. 4. Conclusion When refineries do not utilize vacuum distillation, the high temperature that the crude is exposed to significantly increases the fouling rate in the heat exchangers, heaters, and atmospheric distillation column. This is primarily due to the thermal cracking of the large crude molecules and the formation of new bigger fouling molecules. A higher temperature instigates asphaltene precipitation, especially in blended high paraffin tight crudes that are incompatible. A continuous loop-fouling device can be used to quickly and quantitatively determine the amount of coke formed for different crudes and compositions. The data obtained from this experiment is valuable for comparing crude fouling tendency, the effect of blending different crude oils, and useful for


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evaluating the application of crude oil antifoulants, but it might not work well for measuring the fouling rate. The data from this research seems to suggest that, at temperatures in excess of 700°F, a higher dosage of crude oil antifoulant additives may cause more fouling to occur rather than reduce it. Acknowledgment. The authors are grateful to American Refining Group (ARG) for supporting this project. Thanks also extended to Prafulla Patil, Kurt Raymond, and John Peterson. Author Information Corresponding Author *Tel: +1 814-368-1244. E-mail: [email protected] Funding Sources American Refining Group’s R&D division has covered 100% of the cost for this research. Notes The authors declare no competing financial interest. Supporting Information. Picture of in-house continuous flow loop laboratory fouling rig without insulation, A. Coke from filtered Crude B after the use of the laboratory fouling rig (x40 magnification), B. Clean reactor before use in fouling rig, C. References


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(1) W. L. Van Nostrand; S. H. Leach; J. L. Haluska. Economic Penalties Associated with the Fouling of Refinery Heat Transfer Equipment. Fouling of heat Transfer Equipment, Troy, New York, and Hemisphere. 1981. (2) S. Macchitto et al. Fouling in Crude Oil Preheat Trains: A systematic Solution To An Old Problem, Proceedings of International Conference on Heat Exchanger Fouling and Cleaning VIII, 2009. (3) E. M. Ishiyama; W. R. Paterson; D.I. Wilson. The Effect of Fouling on Heat Exchanger Transfer Pressure Drop and Throughput in Refinery Preheat trains: Optimization of cleaning Schedules, Proceeding of 7th international conference on heat exchanger fouling and cleaning- Challenges and Opportunities. 2007. (4) S. J. Pugh; G.F. Hewitt; H. Muller-Steinhagen. Heat Exchanger Fouling In The Pre-Heat Trains Of A Crude Distillation Unit- The Development of A ‘User Guide’. United Engineering Conference, Heat Exchanger Fouling: Fundamentals and Technical Solutions. 2001. (5) B. L. Yeap. Design of Heat Exchanger Networks with Fouling Mitigation, CGPS dissertation: University of Cambridge, UK, 2001. (6) H. Z. Kister. Are Column Malfunctions Becoming Extinct- or Will They Persist in the 21st Century? Trans IChemE, 1997, 75 (6), 563-589 (7) H. Z. Kister. What Caused Tower Malfunction in the Last 50 Years, Trans IChemE, 2003, 81 (1), 5-26.


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(8) Irwin A. Wiehe; Raymond J. Kennedy. The Oil Compatibility Model and Crude oil Incompatibility, Energy and Fuels, 2000, 14, 56-59. (9) Irwin A. Wiehe; Raymond J. Kennedy. Application of the Oil Compatibility Model to Refinery Streams. Energy and Fuels, 2000, 14, 60-63. (10) Irwin A. Wiehe. Asphaltene Solubility and Fluid Compatibility, Energy and Fuels, 2012, 26, 4004-4016. (11) Z. S. Saleh; R. Sheikoleslami; A. P. Watkinson. Blending Effects on Fouling of Four crude Oils. Proceeding of the 6th international conference on heat exchangers Fouling and cleaning- Challenges and opportunities. 2005. (12) Thomas Garrett; Ahly Rattanakhambay; Neal Robbins; Matthew Wunder; Thomas Yeung. The challenge of crude oil blending. Digital refining.com. 2016. (13) U.S Energy Information Administrative EIA, website, last updated June 22, 2017. (14) Bruce Wright; Corina Sandu. Problems and Solutions for Processing Tight oils. American Fuel and Petrochemical Manufacturers (AFPM) annual meeting. 2013. (15) Brian Benoit; Jeffrey Zurlo. Overcoming Challenges of Tight/Shale Oil Refining, Processing Shale Feedstocks, 2014, pp. 37. (16) Tim Olsen. Working With Tight Oil, American Institute of Chemical Engineers (AICHE). 2015, pp. 35. (17) B. D. Crittenden; S. T. Kolaczkowski; I. L. Downey. Fouling of crude oil preheat exchangers. Chem. Eng. Res. Des. 1992, 70 (6A), 547-557.


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(18) Francesco Coletti; Geoffrey F. Hewitt. Crude oil Fouling. Deposit Characterization, and Modeling. Book edited by. Elsevier Inc., 2015. (19) Rostani, K. Effect of Crude Oil Vanadium Porphyrin Content and Blending on Heat Exchanger Fouling (Ph.D. Thesis). Department of Chemical Engineering and Chemical Technology, Imperial College, UK. 2014. (20) Andrew Young et al. Characterization of Crude Oils and their Fouling Deposit Using a Batch Stirred Cell System. International Conference on Heat Exchanger Fouling and Cleaning VIII. 2009. (21) A. D. Smith. Analysis of Fouling Rate and Propensity for Eight Crude Oil Samples in Annular Test Section. International Conference on Heat Exchanger Fouling and Cleaning, Budapest, Hungary. 2013. (22) M. Ratel; Y. Kapoor; Z. Anxionnaz-Minvielle; L. Seminel; B. Vinet. Investigation of Fouling Rates in a Heat Exchanger Using an Innovative Fouling Rig. International Conference on Heat Exchanger Fouling and Cleaning, Budapest, Hungary. 2013. (23) P. Eaton; R. Lux. Laboratory Fouling Test Apparatus for Hydrocarbon Feedstocks. In: Fouling in Heat Exchange Equipment. ASME HTD, 1984, 35, 33-42. (24) E. E. Banda-Cruz et al. Crude Oil UV Spectroscopy and Light Scattering Characterization. Petroleum Science and Technology, 2016, 8 (34), 732-738. (25) M Agrawala; H W. Yarranton. An Asphaltene Association Model Analogous to Linear Polymerization. Ind. Eng. Chem. Res., 2001, 40 (21), 4664-4672.


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(26) B. Aguilera-Mercado et al. Mesoscopic Simulation of Aggregation of Asphaltene and Resin Molecules in Crude Oils. Energy and Fuels, 2006, 20 (1), 327-338. (27) H. W. Yarranton et al. Effect of Resins on Asphaltene Self-Association and Solubility. Canadian Journal of Chemical Engineering, 2008, 85 (5), 635-642.


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Figure 1. In-house design of crude oil fouling testing rig. 164x112mm (96 x 96 DPI)

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Table 1. Physical Properties and Results of Crude Oil Tested with Laboratory Fouling Rig 165x45mm (96 x 96 DPI)


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Figure 2. Total coke (mg), ∆ API, and micro carbon % of crude after laboratory fouling.


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Equation 1. V denotes volume % and SBN is the Solubility Blending Number of the crude 99x15mm (96 x 96 DPI)


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Energy & Fuels

Equation 2. Colloidal Instability Index of crude oil. 68x10mm (96 x 96 DPI)


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Scheme 1. Series of degradation reactions proposed by Eaton and Lux23. 165x14mm (96 x 96 DPI)


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Energy & Fuels

Picture 1. Coke formed at the distillation tower above the flashing zone. 159x61mm (96 x 96 DPI)


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Figure 3. UV-Vis spectra of Crude A before and after laboratory fouling test.

170x189mm (96 x 96 DPI)


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Energy & Fuels

Figure 4. UV-Vis spectra of 50/50 Crude A/ Crude B before and after laboratory fouling test compared to the 80/20 blend. 170x170mm (96 x 96 DPI)


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Figure 5. Total Coke (mg), ∆ API, and ∆ micro carbon % of Crude A with varying degrees of antifoulant additives after laboratory fouling. 165x87mm (96 x 96 DPI)


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Method and Device for Quantitative Measurement of Crude Oil Fouling

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