4 Asphaltene Stability
4.1 CONVENTIONAL PROCESSING
In the area of petroleum science, asphaltenes are the most studied yet the least understood components of crude oils. An extensive book review of asphaltenes and asphalts was published (Chilingarian and Yen, 2000). The term asphaltenes is used to describe the insoluble content precipitated from petroleum oils using paraffinic solvents. Crude oils are usually characterized by API gravity, distilla-tion range, pour point, sulfur content, metals, salt content, and carbon residue.
The definition of ‘‘heavy oil’’ is usually based on the API gravity of <20. Very heavy crude oils and tar sand bitumens have an API<10. Usually, the higher the density, or lower the API gravity of the crude oil, the higher the sulfur content.
The total sulfur in the crude oil can vary from 0.04 wt% in a light paraffin oil to 5 wt% in a heavy crude oil. Heavy crude oils contain a higher content of heteroatom content, metals, and asphaltenes and have a higher carbon residue.
The carbon residue is roughly related to the asphalt content of the crude oil and the quantity of the lubricating oil fraction that can be recovered (Gary and Handwerk, 2001). Only some crude oils are suitable to produce lube oil base stocks. The literature reported that correlations have been developed to charac-terize the crude oils in terms of typical assay parameters and their effect on increased processing cost related to desalting and corrosion formation (Van den Berg et al., 2003). The effect of crude oil properties and composition on their processing is shown in Table 4.1.
The composition of asphaltenes found in crude oils is important in predicting yields and the operating parameters for different processes. The early literature reported that asphaltenes present in crude oils typically have 79–85 wt% of carbon, 7–9 wt% of hydrogen, 0.3–10 wt% of sulfur, and 0.6–3 wt% of nitrogen (Moschopedis and Speight, 1974). The literature reported on asphaltene stability in crude oils and the influence of oil composition (Wang and Buckley, 2003).
The asphaltenes are usually isolated from crude oils as n-pentane, n-hexane, or n-heptane insolubles and the use of different paraffinic solvents was reported to affect the asphaltene composition. The H=C ratios of the n-heptane insolubles precipitated from crude oils were reported to be lower indicating a higher degree of aromaticity when compared to H=C ratios of the n-pentane insolubles
123
(Speight, 2006). The effect of API gravity on the heteroatom content of n-pentane insolubles, precipitated from Arab crude oils, is shown in Table 4.2.
With a decrease in API gravity of Arab crude oils, and an increase in their viscosity, their n-pentane insolubles were found to have higher S and N contents but lower O content. The use of Arab heavy crude oil also leads to n-pentane insolubles, having a higher H=C and N=C ratios, indicating a lower polyaromatic content. The literature reported that asphaltenes contain S compounds as highly condensed thiophene derivatives. Their N content was reported to be mostly in the form of pyrroles while their O content was reported to contain carboxylic, TABLE 4.1
Effect of Crude Oil Properties and Composition on Their Processing
Crude Oil Properties Typical Range Crude Oil Processing
API gravity 10–50 High gravity is more valuable
Distillation range Vary Indicates product quantity
Pour point Vary Related to wax content
Sulfur, wt% 0.1–5 Low content is more valuable
Nitrogen, wt% 0.1–2 Catalyst poison
Oxygen, wt% 0.1–0.5 Corrosion problem
Metals Vary Catalyst poison
Salt Vary Low content is more valuable
Asphaltenes Vary Low content is more valuable
Carbon residue Vary Low content is more valuable
Source: From Sequeira, A. Jr., Lubricant Base Oil and Wax Processing, Marcel Dekker, Inc., New York, 1994. Reproduced by permission of Routledge=Taylor & Francis Group, LLC.
TABLE 4.2
Effect of API Gravity on Heteroatom Content of n-Pentane Insolubles
C5 Insolubles Arab Light,
API 33.8 Arab Medium,
API 30.4 Arab Heavy,
API 28.8
Carbon, wt% 84.23 83.65 83.17
Hydrogen, wt% 7.76 8.31 8.28
Sulfur, wt% 6.3 6.41 7.18
Nitrogen, wt% 0.75 0.65 0.84
Oxygen, wt% 0.96 0.98 0.53
H=C ratio 1.1 1.18 1.19
N=C ratio 0.009 0.008 0.01
Source: From Siddiqui, M.N., Petroleum Science and Technology, 21, 1601, 2003. Reproduced by permission of Taylor & Francis Group, LLC, http:==www.taylorandfrancis.com.
group in asphaltenes appears as a sharp peak at 3610 cm1 and a hydrogen bonded OH appears as a broad peak at 3100–3350 cm1 (Siddiqui, 2003).
According to the literature, n-pentane insolubles, precipitated from Arab heavy crude oil, have less acidic but more basic properties (Siddiqui, 2003). Intermo-lecular forces in aggregates of asphaltenes and resins other than H-bonding, such as van der Waals, electrostatic, and charge transfer, were also reported (Murgich, 2002). The effect of API gravity on the metal content of n-pentane insolubles, precipitated from Arab crude oils, is shown in Table 4.3.
The use of Arab heavy crude oils also leads to n-pentane insolubles having a higher metal content, mostly V and Ni, but also a higher content of Ca, Mg, and Al indicating a decrease in the efficiency of the desalter to remove salts from heavy oils. The nonporphyrin V and Ni were reported to be associated with heteroatoms, such as S, N, and O, or are associated with the aromatics in metalloporphyrins (Siddiqui, 2003). The n-pentane insolubles precipitated from Arab heavy crude oil were reported to have the highest content of V and Ni. The use of gel permeation chromatography (GPC) indicated that the n-insolubles, precipitated from Arab heavy crude oil, have the highest molecular weight (Siddiqui, 2003).
Thefirst step in refining involves the fractionation of the crude oil at atmos-pheric pressure. The next step is the fractionation of the high boiling fraction under vacuum. The conventional processing of crude oils leads to the atmospheric and vacuum residues. There are different methods to measure the carbon residue of petroleum oils. Carbon residue measurements which use the Conradson carbon
TABLE 4.3
Effect of Heavy Crude Oil on Metal Content of n-Pentane Insolubles
C5 Insolubles Arab Light,
Source: From Siddiqui, M.N., Petroleum Science and Technology, 21, 1601, 2003. Reproduced by permission of Taylor & Francis Group, LLC, http:==www.taylorandfrancis.com.
residue (CCR) test procedure are usually reported as carbon residue. The literature reported that carbon residue of an oil can be also measured by the Ramsbottom carbon residue (RCR) test (Shell, 2001). Despite a wide spread use of carbon residue data as quality control parameter for petroleum feedstocks and products, its chemical significance is not known. The early literature reported on the additivity of CCR data and its dependence on elemental composition for residual oils in relation to optimization of thermal upgrading (Roberts, 1989). The prop-erties and composition of different residue and vacuum gas oil, produced from Kuwaiti crude oil, are shown in Table 4.4.
The atmospheric residue, from Kuwaiti crude oil, was reported to have an API gravity of 13.9 and a pour point of 188C. The composition indicated the presence of 4.4 wt% of sulfur, 0.26 wt% of nitrogen, and the presence of metals, including 50 ppm of V and 14 ppm of Ni. The asphaltene content, measured as n-heptane (C7) insolubles, was reported to be 2.4 wt%. The atmospheric residue, from Kuwaiti crude oil, was also reported to have carbon residue of 12.2 wt%, measured as CCR, and 9.8 wt%, measured as RCR (Speight, 1999).
The vacuum gas oil (VGO), from Kuwaiti crude oil, indicated a higher API gravity of 22.4, a lower S content of 2.97 wt%, a lower N content of 0.12 wt%, and practically no metals and no asphaltenes. VGO was reported to have a low carbon residue of 0.09 wt%, measured as CCR, and a low carbon residue of<0.1 wt%, measured as RCR. During crude oil distillation, asphaltenes are not volatilized and remain in the vacuum reduced crude along with the metals and no asphaltenes and metals are present in VGOs.
The vacuum residue, from the same Kuwaiti crude oil, indicated a lower API gravity of 5.5, a higher sulfur content of 5.45 wt%, a higher N content of 0.39 wt%, and a high metal content, including 102 ppm of V and 32 ppm of Ni.
TABLE 4.4
Properties and Composition of Different Residue and Vacuum Gas Oil
Properties Atmospheric Residue Vacuum Gas Oil Vacuum Residue
API gravity 13.9 22.4 5.5
Viscosity at 1008C, cSt 55 — 1900
Pour point,8C 18 — —
Sulfur, wt% 4.4 2.97 5.45
Nitrogen, wt% 0.26 0.12 0.39
Vanadium, ppm 50 <1 102
Nickel, ppm 14 <1 32
C7 insolubles, wt% 2.4 0 7.1
Carbon residue (CCR), wt% 12.2 0.09 23.1
Carbon residue (RCR), wt% 9.8 <0.1 —
Source: From Speight, J.G., The Chemistry and Technology of Petroleum, 3rd ed., Marcel Dekker, Inc., New York, 1999. Reproduced by permission of Routledge=Taylor & Francis Group, LLC.
The asphaltene content, measured as C7 insolubles, increased to 7.1 wt% and a CCR carbon residue was also reported to significantly increase to 23.1 wt%
(Speight, 1999). The chemistry of volatile aromatic products from the thermal decomposition of asphaltenes is shown in Table 4.5.
The presence of highly condensed aromatic structures in asphaltenes, precipi-tated from crude oils, leads to formation of coke precursors during their thermal decomposition. The literature reported that thermal decomposition of asphaltenes leads to a high content of nonvolatile residue, in a range of 38–63 wt% (Speight, 1988). More recent literature reported that at the temperature of 3508C–8008C, the pyrolysis of asphaltenes produced a substantial amount of alkanes, having up to 40 carbon atoms per molecule, and O-containing compounds identified to be carboxylic, phenolic, and ketonic type molecules. The pyrolysis of asphaltenes indicated that the oxygen-containing molecules were found to be more volatile (Speight, 1999). The use of scanning electron microscopy (SEM) identified the presence of S, V, Fe, Mg, and Si in asphaltenes precipitated from vacuum residue using different n-alkane solvents. Depending on the precipitating solvent, some asphaltenes were also reported to contain Zn and Sn (Bragado et al., 2001).
The presence of polyaromatic hydrocarbons and metals might lead to a decrease in volatility of some heteroatom containing molecules and an increase in non-volatile residue.
4.2 HYDROPROCESSING
The use of catalytic and thermal cracking processing, under the high temperature conditions, affects the composition of petroleum products and their asphaltene content. Hydrotreating is used to remove sulfur by catalytically reacting
TABLE 4.5
Chemistry of Volatile Aromatic Products from the Thermal Decomposition of Asphaltenes
Molecular Type Chemistry
1-Ring aromatics Alkylbenzenes
Polynuclear aromatics
2-Ring condensed aromatics Alkylnaphthalenes
3-Ring condensed aromatics Alkylphenanthrenes
4-Ring condensed aromatics Alkylchrysenes
Aromatic S-containing compounds Alkylbenzothiophenes Alkyldibenzothiophenes Source: Reprinted with permission from Speight, J.G., Polynuclear Aromatic Compounds, Ebert, L.B., ed., American Chemical Society, Washington, DC, 1988. Copyright American Chemical Society.
other industries. While hydrotreatment (HT) and hydrocracking (HC) convert low grade feedstocks to gasoline and distillate fuels, the variability in the feed composition affects the severity of processing conditions. Sulfur compounds, such as mercaptans and sulfides, found in light cuts are easy to remove (Sanchezllanes and Ancheyta, 2004). The literature reported on the analysis of heavy ends of petroleum needed to predict the effect of conversion on the volume of products influid catalytic cracker (FCC) unit and HC. In a modern refinery, the catalytic cracker is used to crack paraffinic atmospheric and VGOs while the hydrocracker is used to crack more aromatic cycle oils and coker distillates (Gary and Handwerk, 2001). Coking of vacuum residue was used primarily to produce coker gas oil suitable for use as a feed to a catalytic cracker. This reduced the coke formation on the cracker catalyst (Gary and Handwerk, 2001). More aromatic coker distillate feeds resist catalytic cracking but are easily cracked in the presence of pressure and hydrogen. In recent years, the coking process is also used to prepare hydrocracker feedstocks (Gary and Handwerk, 2001). The typical HC feedstocks and HC petroleum products are shown in Table 4.6.
Distillation separates crude oil into useful components which may be end products or feedstocks for other refinery processes, such as catalytic cracking, hydrocracking, or thermal cracking. Delayed andfluid coking produces a signifi-cant amount of light olefins, including ethylene, propylene, and butane. The naphtha fraction was reported to contain olefins and diolefins and the presence of diolefins requires special treatment to prevent polymerization in hydrotreaters (Gray and McCaffrey, 2002).
Atmospheric residue desulfurization process is widely used for residue upgrading and different catalysts are used to decrease the S, N, and metal contents of atmospheric residue. The straight-run atmospheric residue, used as feed, is high
TABLE 4.6
Typical Hydrocracking Feedstocks and HC Petroleum Products
HC Feedstocks HC Petroleum Products
Kerosene Naphtha
Straight-run diesel Naphtha and=or jet fuel Atmospheric gas oil Naphtha, jet fuel and=or diesel Vacuum gas oil Naphtha, jet fuel, diesel, lube oil
FCC LCO Naphtha
FCC HCO Naphtha and=or distillates
Coker LCGO Naphtha and=or distillates
Coker HCGO Naphtha and=or distillates
Source: From Gary, J.H. and Handwerk, G.E., Petroleum Refining, Technology and Economics, 4th ed., Marcel Dekker, Inc., New York, 2001.
Reproduced by permission of Routledge=Taylor & Francis Group, LLC.
atmospheric residue was reported to contain a lower S content of 0.53 wt%, a lower N content of 0.21 wt%, a lower V content of 10 ppm, and a lower Ni content of 6 ppm. After HT, the atmospheric residue was also reported to contain a lower asphaltene content of 1.3 wt% and have a lower carbon residue of 5.2 wt%
(Marafi and Stanislaus, 2001). A rapid coke build up on the catalyst was observed during the HT of atmospheric residue. The catalyst deactivation by a coke depos-ition was reported to be affected by the feedstock composdepos-ition (Marafi and Stanislaus, 2001). The effect of partially hydrotreated atmospheric residue on the composition of distilled VGO is shown in Table 4.7.
VGO, distilled from the partially hydrotreated atmospheric residue, was reported to have a lower S content of 0.4 wt%, N content of 0.11 wt%, and have no metals and no asphaltenes. VGO, distilled from the partially hydrotreated atmospheric residue, was also reported to have a lower carbon residue of 0.02 wt% (Marafi and Stanislaus, 2001). When using the alumina supported hydrotreat-ing catalysts, the alumina support provides the required porosity, surface area, and the acidic and basic sites. The acidity of catalysts can be modified by using sodium and fluoride ions as acidity modifying agents (Marafi and Stanislaus, 2001). An increase in the catalyst acidity by the use of fluoride, at low level of 2 wt%, increased the HDS and HDN activity, however, the use of higherfluoride content of 5 wt% decreased the catalyst activity. The use of catalyst containing sodium increased the coke formation leading to catalyst deactivation (Marafi and Stanislaus, 2001). Although coke deposition on the catalyst cannot be totally eliminated, it can be minimized. The literature reported that to protect the catalyst, it is important to reduce the nitrogen content of the feed to below 10 ppm (Speight, 1999). The literature reported that the straight-run atmospheric residue, used as
TABLE 4.7
Effect of Partially HT Atmospheric Residue on Composition of VGO
Properties Partially HT Atmospheric Residue Distilled VGO
API gravity 20.49 24.94
Density at 158C, g=mL 0.9304 0.904
Sulfur, wt% 0.53 0.4
Nitrogen, wt% 0.21 0.11
Vanadium, ppm 10 0
Nickel, ppm 6 0
Asphaltenes, wt% 1.3 0
Carbon residue, wt% 5.2 0.02
Source: From Marafi, M. and Stanislaus, A., Petroleum Science and Technology, 19, 697, 2001. Reproduced by permission of Taylor & Francis Group, LLC, http:==www.taylorandfrancis.com.
feed, needs to pass through different catalyst beds to achieve the required product quality (Hauser et al., 2005). The effect of different catalyst beds on the properties and composition of straight-run atmospheric residue is shown in Table 4.8.
When atmospheric residue passed through catalyst bed # 1, mostly designed to remove metals, a decrease in viscosity, S, metals, asphaltenes, and carbon residue is observed. However, no significant reduction in N content was reported.
After hydrotreated atmospheric residue was passed through an additional catalyst bed # 2, mostly designed to remove S, a further decrease in viscosity, S, metals, asphaltenes, and carbon residue is observed. Only after passing through the second catalyst bed, a reduction in N was reported. According to literature, asphaltenes are considered to be coke precursors because they have a high molecular weight, high aromaticity, and are the least reactive components of the feed (Hauser et al., 2005). The effect of different catalyst beds on the content and composition of asphaltenes is shown in Table 4.9.
After passing through two different catalyst beds, a significant decrease in the asphaltene content is observed. The presence of oxygen is difficult to measure and, while the literature reports on the presence of heteroatom content, such as S and N in asphaltenes, a high content of calculated oxygen is also observed.
Despite a decrease in heteroatoms, metals, asphaltenes, and carbon residue, the hydrotreated feeds are not‘‘easier feedstocks’’ in terms of preventing the coke formation and catalyst deactivation (Hauser et al., 2005). The propensity to form coke on different catalysts was studied and the coking tendency was higher for hydrotreated atmospheric residue, having a higher saturate content and depleted of asphaltenes, when compared to straight-run atmospheric residue. According to the literature, the carbon content of spent catalyst beds # 1 increased to about TABLE 4.8
Effect of Different Catalyst Beds on Properties and Composition of Residue
Properties Atmospheric,
Residue Feed Catalyst Bed # 1,
HDM Process Catalyst Bed # 2, HDS Process
Viscosity at 508C, cSt 765.1 208.5 112.9
Carbon, wt% 83.4 85.6 86.5
Carbon residue, wt% 12.2 8.5 5
Source: Reprinted with permission from Hauser, A. et al., Energy and Fuels, 19, 544, 2005.
Copyright American Chemical Society.
18 wt% while the carbon content of spent catalyst bed # 2 increased to about 23 wt% (Hauser et al., 2005). Under industrial conditions, the initial catalyst deactivation is caused by rapid coke deposition followed by metal accumulation and very rapidfinal deactivation by pore mouth clocking. The literature reported on the use of an NMR technique to analyze the chemistry of coke deposited on the catalysts which indicated a less aromatic character of coke generated from hydrotreated feed. According to the literature, another route to coking which is formation and polymerization of olefins formed during the HC step needs to be considered (Hauser et al., 2005). The effect of hydrotreating temperature on S, metals, and asphaltene contents of Kuwaiti product oil, obtained from atmos-pheric residue, is shown in Table 4.10.
TABLE 4.9
Effect of Different Catalyst Beds on Content and Composition of Asphaltenes
Composition Atmospheric,
Residue Feed Catalyst Bed # 1,
HDM Process Catalyst Bed # 2, HDS Process
Oxygen, wt% (calc.) 6 10.5 3.9
Vanadium, ppm 561 8 7
Nickel, ppm 172 5 3
Source: Reprinted with permission from Hauser, A. et al., Energy and Fuels, 19, 544, 2005. Copyright American Chemical Society.
TABLE 4.10
Effect of HT Temperature on Composition of Kuwaiti Product Oil
Arabian Heavy Crude Oil,
Source: Reprinted with permission from Bartholdy, J. et al., Energy and Fuels, 15, 1059, 2001.
Copyright American Chemical Society.
The literature reported that at low hydrotreating temperature, the main reaction is hydrogenation leading to stable products. At higher temperatures of 3708C–3908C, the process becomes cracking dominated and the sludge formation is observed (Bartholdy et al., 2001). The effect of hydrotreating temperature on the composition and molecular weight of asphaltenes, separated from Kuwaiti product oils, is shown in Table 4.11.
An increase in the HT temperature leads to a decrease in asphaltene content, having a lower heteroatom content and a lower molecular weight. With a decrease in asphaltene content, a decrease in product stability was reported.
Kuwaiti product oils, produced from atmospheric residue below 3708C, were reported to have good stability during their transportation and storage. With an increase in the HT temperature, despite a lower asphaltene content, a decrease in product stability leads to sludge. Below 3708C, the main reaction was reported to be dominated by hydrogenation leading to stable products while above 3708C, it was reported to be mainly dominated by HC leading to less stability and sludge (Bartholdy et al., 2001).
To increase the production of fuels, cracked stocks are blended with straight-run products which can lead to an increase in their instability. The literature reported on the use of methanol extraction and hydrostabilization to improve the stability of blends containing cracked light cycle oil (LCO) and straight-run gas oil (SRGO) (Sharma et al., 2003). The accelerated storage stability test indicated that some HCGO, produced under the same processing conditions, were found to have a different storage stability. The literature reported that the furfural
To increase the production of fuels, cracked stocks are blended with straight-run products which can lead to an increase in their instability. The literature reported on the use of methanol extraction and hydrostabilization to improve the stability of blends containing cracked light cycle oil (LCO) and straight-run gas oil (SRGO) (Sharma et al., 2003). The accelerated storage stability test indicated that some HCGO, produced under the same processing conditions, were found to have a different storage stability. The literature reported that the furfural