Characterization of Upgraded Oil Fractions Obtained by Slurry-Phase

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Characterization of upgraded oil fractions obtained by slurry-phase hydrocracking at low severity conditions using analytical and ore catalysts Alexander Quitian, and Jorge Ancheyta Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b01433 • Publication Date (Web): 09 Aug 2017 Downloaded from http://pubs.acs.org on August 12, 2017

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Characterization of upgraded oil fractions obtained by slurry-phase hydrocracking at low severity conditions using analytical and ore catalysts Alexander Quitian†,‡, Jorge Ancheyta‡* † Facultad de Química, Universidad Nacional Autónoma de México, Ciudad Universitaria, Coyoacán, Mexico City, 04510 ‡Instituto Mexicano del Petróleo, Eje Central Lázaro Cárdenas Norte 152 Col. San Bartolo Atepehuacan, Mexico City, 07730, Email: [email protected]

ABSTRACT A heavy crude oil and its upgraded oils obtained by batch slurry-phase hydrocracking at low severity conditions without and with analytical grade and ore catalysts rich in iron and molybdenum were fractionated by atmospheric distillation and deasphalted aiming at identifying the fraction responsible for the upgrading of the flow properties. Light cuts were separated at 260°C from distillation bottoms. This latter fraction was further deasphalted with heptane at 25 kg/cm2 and 60°C, for separation of maltenes and heptane insolubles. The heptane insolubles by Soxhlet extraction were subsequently fractionated in asphaltenes and toluene insolubles. Light cuts, bottoms and maltenes were characterized by density, viscosity, simulated distillation and elemental analysis. Light cuts were also characterized by PIONA analysis. Elemental analysis, 1H and

13

C nuclear magnetic resonance, X-ray

diffraction and molecular weight distribution by gel permeation chromatography were carried out for asphaltenes and toluene insolubles. The upgrading of flow properties of hydrocracked products was found to be due to the increase of light cuts and maltenes contents caused by hydrocracking of asphaltenes, as well as to their upgraded properties with respect to the heavy crude oil, which are proportional to the active metal content and hydrogenation capacity of the catalysts (Mo>Fe). Keywords: slurry-phase catalyst, ore, heavy crude oil, upgraded oil, hydrocracking. 1.

INTRODUCTION

The treatment of crude oils, bitumen or residues with aliphatic solvents allows for the separation of a dark solid of different shades from brown to black, known as asphaltenes. 1 ACS Paragon Plus Environment

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This fraction is the main responsible of the high density and viscosity of heavy oils making difficult their transportation and processing. They also have the largest number of heteroatoms (S, N, O) and may even have more than 90% of the metals present in the crude oil.1,2 Asphaltenes have the main following properties: •

Hydrocarbon structures with varying amounts of heteroatoms and hydrogen/carbon atomic ratio of 0.85 to 2.

•

Usually they have high contents of oxygen, sulfur and nitrogen of 0.3-4.9%, 0.310.3% and 0.6-3.3% respectively. 1,3–5

•

The content and composition of asphaltenes depend on the nature of heavy oil, as well as on the operating conditions used in its separation: type of solvent, solvent/feed ratio, contact time, temperature and pressure.

•

Polynuclear aromatic rings attached to aliphatic side chains wherein the heteroatoms are distributed in both components (aromatic and aliphatic) of the molecule forming a lamellar structure.

•

High molecular weight of asphaltenes indicates high aromaticity and heteroatom content. They form aggregates by several sheets placed one above the other and which are held together by physicochemical forces.

•

Weight and molecular structure of asphaltenes have not been able to determine with accuracy because they are mixtures of compounds with different structures and these tend to form aggregates even when they are added at very low concentrations, which hinders determination of the characteristic structural parameters of their molecule 6–8.

•

Insolubles in nonpolar hydrocarbons with surface tensions less than 25 mN/m at 25°C, such as light naphtha and low molecular weight alkanes, being n-pentane and n-heptane the most commonly used.

•

Soluble in hydrocarbons with surface tension above 25 mN/m at 25 ° C, among which are pyridine, carbon disulfide, carbon tetrachloride and aromatic hydrocarbons such as benzene and toluene.2,9–13

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Asphaltenes are responsible for a series of problems when handling heavy oils such as plugging of pipelines and equipment, reducing the production of distillable products in the refining of crude oil because of their high resistance to thermal and catalytic cracking. In the case of catalytic hydroprocessing, they are responsible for the deactivation of catalysts, due to coke formation, which is deposited on catalytic materials.14–19 The effect of moderate and severe reaction conditions of hydrocracking of heavy oil using supported catalysts have shown that the conversion of asphaltenes to lighter fractions is enhanced with increased severity of the reaction. At temperatures above 400°C, there is a high conversion of asphaltenes during hydrocracking of heavy oils. The asphaltenes of hydrotreated oils obtained at above 360°C have lower molecular weight, aliphatic carbon content, H/C ratio and therefore an increase in aromaticity factor as compared with the feed. Similar properties of asphaltenes from hydrotreated oils are obtained due to the effect of reaction time at moderate and severe conditions, especially at long residence times. Instead, the increased pressure has not significant effect in reducing asphaltenes content or in their structure, except when pressures are higher than 75 kg/cm2.1,20–25 The conversion and type of structural changes of asphaltenes in the hydrocracking of heavy oils depend on the properties of the catalyst used. Supported catalysts with larger pore diameter produce higher conversions of residue fraction and asphaltenes per unit surface area. It is commonly accepted that a porosity of 12-15 nm is sufficient for maximum conversion of asphaltenes to maltenes. However, the accessible catalyst surface area per unit volume of reactor decreases as the catalyst pore diameter is increased. Also high acidity of the support leads to an increase in the conversion of asphaltenes. Furthermore, a larger pore size and acidity of the support favor the rapid deactivation of the catalyst due to the deposition of coke and metals that occurs during the hydrocracking of feeds with high amount of impurities.20,26–28. The current low oil prices, the high cost and the rapid deactivation of the supported catalysts have favored the development of processes in slurry phase hydrocracking in recent years. Compared with studies of the effect of operating conditions on the properties of asphaltenes using supported catalysts, there are few studies in the case of hydrocracking with slurry catalysts. Some studies used water-soluble and oil-soluble catalysts in order to 3 ACS Paragon Plus Environment

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study the effect of operating conditions at moderate to high severity, which have shown similar behavior than the supported catalysts in terms of conversion, chemical and structural changes of asphaltenes.29,30 In the case of the active metals used in both types of catalysts (supported or slurry), molybdenum in its sulfide species (MoS2) is the most used due to its high ability to catalyze the hydrogenation reaction hence inhibiting condensation reactions. However, it has been shown that the addition of small amounts of iron, nickel, cobalt, and silicon can enhance the hydrogenation reactions and thus increasing the conversion and causing some significant chemical and structural changes of asphaltenes.31–33 In a previous study, a comparison of different ore and analytical grade catalysts was carried out for the upgrading of fluidity properties of heavy oil by partial hydrocracking. At low severity conditions, it was demonstrated that suitable viscosity and API gravity of the upgrade oil can be achieved. This behavior was attributed to changes in the oil composition. However, the precise reasons for such changes remained unknown.34 In this research, asphaltenes and maltenes obtained from upgraded oils are characterized by different techniques in order to identify the fraction responsible for the upgrading of fluidity properties of crude oil. 2.

EXPERIMENTAL

The general procedure for the fractionation of the upgraded crude oils is shown in Figure 1. The samples were initially fractionated by atmospheric distillation into light cuts with boiling point lower than 260°C and bottoms. The latter cut was deasphalted to separate the insolubles in heptane and maltenes. The insolubles fractions in heptane were further fractionated in asphaltenes and toluene insolubles. 2.1. Materials The properties of the oil samples (heavy crude oil and upgraded oils) are presented in Table 1. The upgraded oils were obtained by slurry-phase hydrocracking at the same reaction conditions in batch operation (3.92 MPa, 380°C, 800 rpm, 4 h) in a 1 L stirrer Parr reactor model 4843 equipped with automatic control for temperature, pressure and stirring rate. 200 grams of heavy crude oil were used for all experiments, without catalyst and using different 4 ACS Paragon Plus Environment

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pulverized catalysts of analytical and mineral grades (with particle size less than 5 µm) in a concentration of 5000 ppm based on the content of metal active (Mo or Fe). The liquid yields of upgraded oils are also shown in the Table 1. The aliphatic solvent used for the precipitation of asphaltenes was anhydrous n-heptane (98.5% purity) of Sigma-Aldrich. 2.2.

Distillation of crude oils samples

200 g of crude oil samples were atmospherically distilled to separate light cuts with boiling points lower than 260°C using the equipment described in ASTM D86-16a standard. The distillation bottom was used for the separation of insolubles in n-heptane. 2.3. Deasphalting The separation of asphaltenes and maltenes was carried out in a model 4530 Parr reactor with a capacity of 2000 mL, which is equipped with a control system for pressure, temperature and stirring rate. The reactor is loaded with n-heptane and distillation bottoms in a mass ratio of 5:1. After sealing the reactor, it is pressurized with nitrogen at 2.5 MPa, heated to 60°C with heating rate of 5°C/min, stirring rate is adjusted at 900 rpm and these conditions are maintained for one hour. Then the heating is kept constant for another hour and subsequently precipitation of asphaltenes is allowed for 12 hours. Once the reactor is depressurized and opened, the liquid is decanted and filtered using a Whatman Glass microfiber filter, Grade 934-AH to remove asphaltenes that could be suspended. Asphaltenes are collected from the bottom of the reactor, deposited on the filter and washed with heptane until liquid obtained in the filtration is colorless. Finally, asphaltenes are purified by Soxhlet extraction with toluene and dried at 110°C in order to separate them from the toluene insolubles. The filtrated and collected liquid in washed asphaltenes is vacuum distilled at a pressure of 10 mmHg and 40°C using a rotary evaporator Buchi model R-300 to separate the heptane from the maltenes. 2.4. Products characterization 5 ACS Paragon Plus Environment

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API gravity, viscosity, simulated distillation and elemental analysis were determined for the light cuts (< 260°C), distillation bottoms and maltenes. Density and viscosity were performed in a densimeter/viscometer Anton Paar SVM model 3000 according to ASTM D4052 and ASTM D7042 methods respectively. Simulated distillation was measured using a gas chromatograph Agilent 7890A following the ASTM D7169 method. Elemental analyses were done in a Perkin Elmer Model Analyzer Series II 2400 (CHNS-O). PIONA analysis of the light cuts was carried out on a Varian CD-3800 gas chromatograph with a column of 100 m x 0.25 µm with automatic injector and a flame ionization detector (FDI) using the ASTM D6730 method. Asphaltenes were characterized by density and structural parameters. Density was determined using the ASTM D71 method. The morphology and microstructural parameters of the asphaltenes was performed by X-ray diffraction in a Siemens D500 X-ray Powder Diffraction (XRD) using CuKα1 radiation with λ=1.5416 Å operating at 35 kV and 35 mA. The scans were performed in the angular range from 4 to 40° (2θ°) with a scan speed of 0.02°/s and using 0.1 g of asphaltenes. The composition of toluene insolubles was determined by X-ray fluorescence in a Siemens D500 diffractometer with Cu anode and graphite mono-chromed, using CuKα radiation (λ=1.450589). Diffraction sweeps were performed in the range of 2θ angles between 0-5° and 10-70° with a scan rate of 0.5 °min-1. The crystalline phases were identified using the references of the data method of JCPDS powders and a specific software installed in the diffractometer for the identification of peaks. The content of coke in toluene insolubles was determined by the ASTM D2974-97 standard for the organic matter. The distributions of molecular weights and the average molecular weight of asphaltenes and toluene insolubles were determined by gel permeation chromatography (GPC) in an Agilent HP 1100 Series HPLC System using a PL aquagel-OH MIXED-H Column. The samples were diluted in a concentration of 1g/lt using as eluent tetrahydrofuran with a flow rate of 1 ml/min. Nuclear magnetic resonance of 1H and

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C was performed on a Bruker BioSpin GmbH

Spectrometer that was operated at 300 MHz for proton and 75 MHz for carbon. 6 ACS Paragon Plus Environment

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Deuteriochloroform (CDCl3) was used to dissolve the samples of asphaltenes. The calculation of structural parameters was done with methods reported in the literature35,36. 3.

RESULTS AND DISCUSSION

3.1. Atmospheric distillation The use of catalysts permits to obtain upgraded oils with higher content of light cuts in comparison with the upgraded oil without catalyst in which high formation of coke occurs (Table 2). The amount of light cuts increases proportionally with the active metal content in the catalyst (iron or molybdenum) and higher yields are obtained when the active metal used is molybdenum as can be seen in Figure 2. The values reported in this figure are calculated as:

% =

100

(1)

Where # represents the grams of the fraction (e.g. light cuts, bottoms, asphaltenes, etc.) or element (e.g. sulfur). This percentage value could be positive or negative depending on the changes in the content or composition of the heavy crude oil or the upgraded oils. The slurry-phase hydrocracking reactions are believed to occur by thermal cracking of aliphatic compounds which produce free radicals that in the presence of hydrogen and by the action of the catalyst can be hydrogenated and catalytic hydrogenolysis of sulfur, nitrogen and aromatic compounds is promoted. The presence of catalyst in the slurry-phase hydrocracking has the function to inhibit the decomposition and condensation reactions that free radicals can undergo, which are responsible for the high formation of coke and gases in hydrocracking without catalyst.29,37,38 However, the types of active metals present in the slurry-phase catalyst determine its ability to hydrogenate. The slurry-phase catalysts with molybdenum have greater capacity of hydrogenation than the catalysts with iron due to their electronic configuration with orbitals 4d that give them greater ability to do covalently bonds with other atoms and in this way, their oxides and sulfides have crystalline structures with greater numbers of catalytic active sites available than iron oxides and sulfides. These electronic structures permit molybdenum oxides and sulfides to retain their basic electronic properties almost independently of the catalytic environment. Hence molybdenum in these crystalline 7 ACS Paragon Plus Environment

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structures can more easily vary their oxidation states making them more catalytically active with lower adsorption and desorption energies of hydrogen than iron catalyst. For these reasons, the analytical grade molybdenum trioxide and molybdenite catalysts produce lower reduction of distillation bottoms and higher yield of light cuts than analytical grade iron oxide and iron ores, which indicates that distillation bottoms are responsible of upgrading of physical and chemical properties.39–41 The impurities reduce the hydrogenation capacity of the mineral catalysts because they alter the crystalline structure of the small catalyst particles and reduce the number of available active sites of the catalyst. Mineral catalysts that have a lower active metal content produce upgraded oil with lower content of light cuts in comparison with the analytical grade catalysts, therefore they have lower hydrogenation capacity. This is also possibly because mineral catalyst crystals have a more organized crystalline structure, sites with active metal vacancies and a random distribution of their non-catalytically active compounds, making it difficult to absorb, dissociate and transport hydrogen to free radicals. Due to these properties, they inhibit to a lower proportion the free radical addition reactions and it results in lower formation of light compounds and a higher content of asphaltenes in the upgraded oils.34,42–45 In the non-catalytic hydrocracking, there is a small formation of light cuts than in slurryphase catalytic hydrocracking with any of the catalysts studied because the chain propagation reactions of the free radicals occur in a more severely manner. This leads to the formation of gaseous hydrocarbons. The temperature also favors the radical addition reactions and higher molecular weight molecules tend to form coke as was shown in a previous research.34 From the changes in distillation fractions, it can be stated that the amount of light cuts is similar in upgraded oils produced with and without catalyst, and consequently this fraction does not have significant effect on the upgrading of flow properties of the upgraded oils. Therefore, the properties of the distillation bottoms are the main responsible for it. 3.1.1. Properties of light cuts The properties of light cuts are shown in Table 3. Density and viscosity show small differences. However, their elemental analysis, simulated distillation and PIONA 8 ACS Paragon Plus Environment

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composition exhibit more notorious changes. The H/C ratio of the light cuts of the upgraded oils varies from 1.882 (without catalyst) to 1.992 (with molybdenite) and both are higher than that of the light cuts of the heavy crude oil (1.601). From the composition by distillation and PIONA analysis of the upgraded oils, not using catalyst causes an increase in the heavy straight-run naphtha, while the content of n-paraffins, iso-paraffins, naphthenes and aromatics are reduced. In spite of these changes, API gravity and viscosity of light cuts of all samples (heavy crude oil, catalytically and not catalytically upgrade oils) remain more or less the same. This means that the produced light cuts do not contribute significantly to the changes in viscosity and API gravity of the upgraded oils. For a better explanation of these results the contents and compositions reported in Table 4 were used with the mass balance (Table 2) and Equation (1) to calculate the percentage of increase or decrease in grams of the element or fraction with respect to the heavy crude oil. This percentage value could be positive or negative depending on the changes in relative contents and amount in both light cuts and bottoms fractions. The reduction percentage of sulfur amount in the light cuts is shown in Figure 3, which resulted to be greater without catalyst because in the non-catalytic hydrocracking, some aliphatic thiols are decomposed to alkenes and hydrogen sulfide. Although slurry-phase hydrodesulfurization is produced by thermal and catalytic pathways, there is a greater formation of aliphatic and aromatic hydrocarbons with sulfur compounds in their structure. These sulfur compounds come from the slurry-phase hydrocracking of higher molecular weight sulfur compounds by hydrogenolysis of disulfide compounds present in the bottom cuts fraction. Figure 3 shows that the increase in the amount of sulfur in light fractions is proportional to the hydrogenation capacity of the catalyst, which is higher for molybdenum catalyst than iron catalyst. The changes in composition of light cuts are shown in Figure 4. There is a reduction in the contents of light and medium straight-run naphtha fractions without catalyst due to these fractions undergo thermal hydrocracking reactions producing gaseous hydrocarbons.34,46 9 ACS Paragon Plus Environment

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On the contrary, the amount of heavy straight-run naphtha and straight-run gasoil increased due to thermal hydrocracking of the jet fuel, kerosene and light vacuum gasoil fractions. Light cuts of upgraded oils using catalysts undergo minor reduction in light straight-run naphtha fraction, due to the difficult hydrogenation of low molecular weight compounds at low severity conditions.34,46 The light cuts of the upgraded oils with catalyst have a significant increase in the other distillation fractions compared with the product without catalyst because the thermal decomposition reactions of addition and decomposition that undergo the free radicals are inhibited by hydrogenation in the slurry-phase hydrocracking. The variations in composition are higher with increased hydrogenation capacity which enhanced at higher active metal content and for molybdenum as active metal as can be seen in Figure 4. The variation of PIONA fractions is shown in Figure 5. The light cuts without catalyst undergo a reduction in most PIONA fractions except olefins due to they undergo reactions of decomposition (that form gases) and addition (forming heavier compounds). The increase in olefins content without catalyst is typical of thermal hydrocracking and is due to the thermal decomposition reactions that produce them and hydrogen. While the increase in the unidentified compounds is due to the thermal cracking reactions that undergo the heavier compounds of the distillation bottoms. In contrast, PIONA fractions of light cuts of upgraded oils using catalysts undergo an increase of almost all fractions except olefins, which increase with increased hydrogenation capacity of the catalyst. The reduction of olefins and the increase of the other PIONA fractions indicate that the catalysts inhibit the decomposition and addition reactions typical of thermal hydrocracking. Despite the differences between the properties of the light cuts obtained with and without catalysts, they do not have a significant effect on their density and viscosity and thus do not appreciably affect the flow properties of the upgraded oils. 3.1.2. Properties of bottom of distillation The properties of the distillation bottoms of upgraded oils are shown in Table 4. As can be seen, the distillation bottoms of the catalytically produced oils have viscosity values of 10 ACS Paragon Plus Environment

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about half of that of the distillation bottom of the upgraded oil without catalyst. The upgrading of the flow properties of the distillation bottoms is mainly due to the increase of the H/C ratio caused by the reduction of the heavy fractions content (vacuum residue and heavy vacuum gasoil). Flow properties of distillation bottoms of upgraded oils are improved according to the hydrogenation capacity of the catalysts. As discussed above, the catalysts have higher hydrogenation capacity if they have a lower content of impurities and have molybdenum as the active metal. Changes in the sulfur amounts of distillation bottoms of upgraded oils for the different catalysts are shown in Figure 3. Similarly, to light cuts, the reduction of sulfur amount in bottoms without catalyst exhibits the greatest values due to the formation of coke and gas at expenses of the conversion of bottoms. The sulfur reduction with catalyst is proportional to the active metal content, being higher for molybdenum catalysts. The catalytically upgraded bottoms have higher amounts of medium distillation cuts than those without catalyst. The increase in these fractions is lower when analytical grade molybdenum trioxide is used as compared with analytical iron oxide, because the former gives higher production of light cuts and it has better hydrogenation capacity of free radical with low molecular weight (higher amount of light cuts) and therefore, higher ability to inhibit the thermal cracking reactions. Figure 7 shows the reduction of the amount of heavy vacuum gasoil and of the vacuum residue that cause the increase in the light and medium fractions of the distillation bottoms. The bottoms of the upgraded oil without catalyst have greater reduction of heavy vacuum gasoil than vacuum residue because the former has higher aliphatic fraction than the latter. The heavy vacuum gasoil is mainly formed by compounds with higher aliphatic fraction that can be reduced to lighter liquid compounds, while the vacuum residue is mainly composed by compounds with higher aromatic fraction that principally become into coke and gas with a low conversion to liquid products at low severity conditions in the hydrocracking without catalyst. The reduction of the amount of heavy vacuum gasoil and the conversion of vacuum residue with catalysts is also proportional to the hydrogenation capacity of the iron and molybdenum catalysts. The reduction level of these fractions is responsible for the higher 11 ACS Paragon Plus Environment

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upgrading of density and viscosity of the bottoms of the hydrocracked oils with catalyst compared with that without catalyst. Unlike light cuts, significant changes in the composition of the distillation bottoms using catalysts have a great effect on the density and viscosity of these fractions and therefore the upgraded oils with catalyst have better flow properties than the upgraded oil without catalyst. 3.2. Deasphalting process The mass balances of the deasphalting of distillation bottoms from upgraded oils and the reduction of the amount of asphaltenes are shown in Table 2 and Figure 8 respectively. The contents of asphaltenes in bottoms from upgraded oils with catalyst are slightly lower than those obtained without catalyst and the heavy crude oil. As can be seen, the change in the asphaltenes content is not significant enough to explain the reduction of density and viscosity in the upgraded oils, therefore the better flow properties of the upgraded oils with catalyst are due to the changes in the composition of maltenes. The reduction in asphaltenes content without catalyst is due to the thermal decomposition that the highest molecular weight asphaltenes undergo which leads to coke formation. This reduction is greater with catalysts containing molybdenum as they have greater capacity to hydrogenate poly-aromatic rings than iron oxides. The reduction in the amount of asphaltenes is proportional to the active metal content in the catalysts used, which shows that its hydrogenation capacity decreases by the presence of impurities (Figure 8). In the case of the toluene insolubles, their content is higher as the active metal content in the used catalysts decreases. Toluene insolubles are mainly composed by the spent catalyst (Table 2). 3.2.1. Maltenes The properties of maltenes of upgraded oil for the different catalysts are shown in Table 5. The upgrading of flow properties of maltenes depends on the type of catalyst and increases according to the active metal content, which is due to increased H/C ratio that together with the reduction of sulfur amount (Figure 9), enhance as the hydrogenation capacity of the catalysts is higher. 12 ACS Paragon Plus Environment

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The maltenes produced with catalysts have higher amount of middle fractions than those without catalyst (Figure 10). Higher amount of these fractions in the upgraded oil using analytical grade ferric oxide allows it to have similar flow properties than the upgraded oil using analytical grade molybdenum trioxide. With ferric oxide, the reduction of the content of asphaltenes is lower and the amount of light cuts is higher than analytical grade molybdenum trioxide. Figure 11 explains that the increase in the amount of middle fractions of maltenes from the upgraded oils with the different catalysts is due to the reduction in the content of heavy vacuum gasoil and vacuum residue. The reduction of these distillation fractions depends on the type of active metal (Mo> Fe) and the purity of the catalyst. The change in the composition and properties of the maltenes is then the main responsible for the enhanced flow properties of the upgraded oils with catalyst. 3.2.2. Asphaltenes Density, elemental analysis and molecular weight of the asphaltenes of different upgraded oils as function of the catalyst type are shown in Table 6. Density of asphaltenes is lower in the catalyst-enhanced oils due to the increase in their hydrogen/carbon ratio. The H/C ratio of asphaltenes increases as the hydrogenation capacity of the catalysts does. This is due to the increase in the degree of saturation and the reduction of the number of aromatic rings. The amount of sulfur of asphaltenes is also reduced with respect to the active metal content as shown in Figure 12. The results of the elemental analysis show a removal of heteroatoms in asphaltenes which depends on the active metal in the catalyst and on the purity of the catalyst used and its hydrogenation capacity. The molecular weights of asphaltenes are reduced according to the hydrogenation capacity of the catalysts used. This reduction suggests that they undergo thermal hydrocracking and hydrogenation reactions both in the aliphatic chains bonded to the aromatic rings and in the aromatic rings. The polydispersity index shows that the asphaltenes of the different upgraded oils have similar molecular weight distribution compared with the heavy crude oil which is typical of hydrocracking processes at low severity conditions, because the reduction of the molecular weight occurs mainly by diminishing the aliphatic chains 13 ACS Paragon Plus Environment

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bonded to the aromatic rings of asphaltenes, and asphaltenes of the heavy crude oil are chemically similar. Structural parameters by

13

C-NMR and 1H-NMR of asphaltenes are shown in Table 7.

Asphaltenes of the upgraded oils have higher percentage of aromatic carbon and lower percentage of aliphatic carbon than those of the heavy crude oil which results in higher aromaticity and lower molecular weight due to the reduction in the aliphatic chains bonded to polyaromatic nucleus of asphaltenes. Asphaltenes obtained from upgraded oils have lower content of aromatic rings because the catalysts favor the hydrogenation of their aromatic nucleus, and the higher hydrogenation capacity of the catalysts gives a higher reduction of aromatic rings. The hydrogenation of aromatic rings leads to the formation of naphthenic rings which after opening by hydrocracking permit the alkyl side chains to break and hydrogenate in smaller molecules. The aromatic core of the upgraded oils is highly condensed and in the case of upgraded oil without catalyst, there is no significant fragmentation of these rings, which means that their breakdown by thermal hydrocracking is unlikely. NMR results show that the major changes in asphaltenes occur on alkyl chains and naphthenic rings. The asphaltenes from slurry-phase hydrocracking are also formed by the breaking of the carbon-carbon bonds of the aliphatic side chains at the α, β, and γ positions which produces aliphatic hydrocarbons and therefore there is an increase in aromaticity. The crystalline parameters of asphaltenes by X-ray diffraction are reported in Table 8. When asphaltenes of the heavy crude oil undergo slurry-phase hydrocracking reactions without and with catalyst, the distances between aromatic sheets of the asphaltenes (dm) are slightly reduced. The molecular distances between aromatic sheets of asphaltenes obtained by slurry-phase hydrocracking with and without catalyst indicate that the use of catalyst prevents asphaltenes of the heavy crude oil become more compact, i.e. tend to form semicoke or soft coke structures. With respect to the distances between the aliphatic sheets (dᵧ), the number of stacked sheets (M) and the stacking height of the aromatic rings (Lc), they present the highest differences between asphaltenes of the upgraded oils with and without catalyst, and those of the heavy 14 ACS Paragon Plus Environment

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crude oil. These differences are due to the reduction of aliphatic chains of asphaltenes which are the easiest that suffer breakage during slurry-phase hydrocracking at low severity conditions, reducing not only the number of carbons of the asphaltenes but also causing their irregular stacking. Although the reduction of asphaltenes content of upgraded oils with catalyst is not enough to improve significantly the flow properties of the upgrade oils, the change in their composition and structure plays an important role in the upgrading of heavy crude oil by slurry-phase hydrocracking with analytical grade and ore catalysts. 3.2.3. Toluene insolubles As shown in Figure 13, the amount of coke in toluene insolubles of the upgraded oils without catalyst is higher than using it, because catalysts inhibit its formation by hydrogenation reactions. Coke formation is lower in molybdenum catalysts than iron catalysts and is proportional to their metal active content. The results of X-ray diffraction and X-ray fluorescence are shown in Table 9. X-ray diffractions of the Fe2O3 analytical grade, magnetite catalysts, and toluene insolubles of heavy crude oil, upgraded oil without catalyst and upgraded oil with Fe2O3 analytical grade and magnetite catalysts are shown in Figure. Toluene insolubles of the upgraded oils are mainly composed by spent catalyst and coke. During the slurry-phase hydrocracking, the oxides of the active metals react mainly with hydrogen sulfide to form metal sulfides which are catalytically more active in hydrogenation reactions. However, the toluene insolubles during hydrocracking increase their content of nickel and vanadium oxides which precipitate together with spent catalyst and coke, then during slurry-phase hydrocracking hydrodemetallization occurs. It is shown in Figure 14 that most of the active metal is recovered together with the toluene insolubles. The organic part of toluene insolubles obtained with catalysts have similar elemental analysis and molecular weight than the organic part of the toluene insolubles without catalyst as can be seen in Table 10. Due to its high molecular weight, it is possible that the organic part of toluene insolubles was formed from the condensation of polyaromatic rings, which occurs during the thermal cracking reactions and therefore, the catalysts used do not 15 ACS Paragon Plus Environment

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favor this type of reactions. The results of the elemental analysis show that the toluene insolubles of upgraded oil using catalyst have a slightly lower sulfur content, which is consistent with the hydrodesulfurization and hydrogenation capacity of analytical grade and ore catalysts. Based on these results, it is observed that the toluene insolubles do not have a great effect on the flow properties of the upgraded oils with catalyst. CONCLUSIONS From the exhaustive characterization of fractions recovered from upgraded oils during slurry-phase hydrocracking at low severity conditions using analytical grade and ore catalysts, the following conclusions can be pointed out: •

The improvement of upgraded oil flow properties is due to the transformation of maltenes and asphaltenes toward light cuts, maltenes with a lower content of vacuum residue and heavy vacuum gas oil, and lower molecular weight asphaltenes.

•

The amounts of light cuts and maltenes in the upgraded oils, as well as the conversion of asphaltenes are increased with respect to the type of catalyst (Mo> Fe) and the amount of active metal in the catalyst.

•

Light cuts of upgraded oils have higher amount of light fractions (naphtha, jet fuel and kerosene) as compared with heavy crude oil and upgraded oil without catalyst.

•

The amounts of light distillates and PIONA fractions are proportional to the type and amount of active metal and hydrogenation capacity of the catalyst. Paraffins, iso-paraffins and naphthenes in the non-catalytic hydrocracking are converted mainly into gaseous hydrocarbons, whereas with catalysts, the cracking reactions are inhibited by hydrogenation of free radicals.

•

The properties and composition of the light cuts does not affect significantly the flow properties of the upgraded oils due to their contents with any catalyst are similar to the upgraded oil without catalyst.

•

Maltenes of upgraded oils with catalyst have higher H/C ratio and lower vacuum residue and heavy vacuum gas oil contents and thus better flow properties than maltenes of the heavy crudeoil. The amount of light fractions and conversion of residue of maltenes are increased according to the type and amount of active metal 16 ACS Paragon Plus Environment

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in the catalyst. The better properties of maltenes and the amount of light cuts are the main responsible for the improvement of properties of upgraded oils. •

The use of catalysts allows for lower reduction of asphaltenes content compared with non-catalytic hydrocracking, in which there is a high coke formation by means of asphaltenes conversion, therefore this fraction has smaller effect on the flow properties of the upgraded oils.

•

Toluene insolubles are mainly composed by coke and spent catalyst. The amount of coke recovered with the toluene insolubles is lower according to the capacity of hydrogenation of the catalyst (Mo>Fe) and the amount of active metal. However, the coke formed with catalyst is chemically similar to that formed thermally by which it is deduced that the catalyst inhibits the formation of coke.

NOMENCLATURE Cal: Fraction of aliphatic carbon Car: Fraction of aromatic carbon fa: Aromaticity factor Hal: Fraction of aliphatic hydrogen Har: Fraction of aromatic hydrogen Hdα: Fraction of aliphatic hydrogen other than alpha HSRN: Heavy straight-run naphtha (177-204°C) HVGO: Heavy vacuum gasoil (454-538°C) Hα: Fraction of alpha aliphatic hydrogen TI: Toluene insolubles JF: Jet fuel (204-274°C) K: Kerosene (274-316°C) LSRN: Light straight-run naphtha (538°C) γ: Subscript that refers to the aliphatic part ACKNOWLEDGEMENTS The authors thank The Mexican Institute of Petroleum for the financial support. A. Quitian also thanks Consejo Nacional de Ciencia y Tecnología (CONACYT) for the PhD Scholarship. REFERENCES (1)

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Table 1. Properties of crude oils Heavy Crude Oil Yield of liquid, wt% API gravity Viscosity at 100°F, cSt

Without catalyst

Upgraded oil Analytical Analytical Hematite Molybdenite MoO3 A Fe2O3

Hematite B

Magnetite

-

88.19

98.99

98.98

99.01

99.00

99.02

99.00

12.71

16.18

19.15

18.58

16.73

16.58

16.26

16.32

6110

319

158

180

195

201

204

201

LSRN MSRN HSRN JF K SRGO LVGO HVGO VR

0.10 5.87 2.33 7.30 5.61 3.73 17.35 17.30 40.41

0.10 7.13 3.67 9.21 6.34 5.62 19.03 13.47 35.43

0.10 8.85 3.70 12.13 8.41 6.38 22.02 14.97 23.44

0.10 8.04 4.05 11.55 8.06 6.19 22.32 15.12 24.57

0.10 7.34 3.94 11.88 8.42 6.39 21.00 14.89 26.04

0.10 7.97 3.52 11.46 8.04 6.20 21.30 15.76 25.65

C H O N S H/C

83.01 9.66 1.52 0.54 5.27 1.367

81.84 11.35 1.82 0.52 4.47 1.654

81.18 11.70 1.84 0.53 4.75 1.719

81.34 11.57 1.86 0.43 4.80 1.697

81.49 11.30 1.78 0.52 4.91 1.654

81.41 11.48 1.82 0.55 4.74 1.682

Composition, wt% 0.10 0.10 9.97 8.85 3.96 3.94 12.84 12.88 8.99 8.71 6.73 6.52 22.32 22.04 14.04 14.79 21.05 22.17 Elemental analysis, wt% 81.3 81.22 11.86 11.74 1.87 1.90 0.51 0.53 4.46 4.61 1.740 1.724


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Table 2. Mass balances for the distillation products of upgraded oils. Distillation products Crude Oil

Heavy crude oil Without catalyst Analytical grade MoO3 Analytical grade Fe2O3 Molybdenite Hematite A Hematite B Magnetite

Light cuts 260°C (wt%) 94.41 93.75 92.25 92.81 92.81 92.93 93.07 92.98

Deasphalting products of bottoms cuts Insolubles in heptane Maltenes (wt%) 79.92 81.13 82.03 81.72 80.83 81.35 80.77 81.07

Toluene insolubles (wt%)

Asphaltenes (wt%)

Total (wt%)

0.38 1.47 2.16 2.05 2.95 2.21 2.49 2.40

19.70 17.40 15.82 16.23 16.22 16.43 16.74 16.53

20.08 18.87 17.97 18.28 19.17 18.65 19.23 18.93


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Table 3. Properties of light cut less than 260°C Heavy crude oil

Upgraded oil

56.93

Without catalyst 57.01

Analytical MoO3 57.80

Analytical Fe2O3 57.75

12.26

12.28

12.41

12.38


0.64 37.29 14.84 46.61 0.36 0.24 0.01 0.00 0.00

0.49 35.33 18.03 45.54 0.31 0.28 0.01 0.00 0.00

0.37 36.82 14.66 47.56 0.33 0.25 0.01 0.00 0.00

C H O N S H/C

85.85 11.53 0.55 0.18 1.89 1.601

84.34 13.32 0.63 0.16 1.54 1.882

Paraffins Isoparaffins Olefins Naphthenes Aromatic Unidentified

23.35 18.07 1.08 9.18 15.11 33.21

17.31 16.64 3.63 7.30 11.79 43.33

API gravity Viscosity at 68°F, cSt

Molybdenite Hematite A

Hematite B

Magnetite

57.67

57.43

57.38

57.55

12.35

12.30

12.31

12.33

0.40 35.57 14.85 48.57 0.34 0.26 0.01 0.00 0.00

0.42 33.59 17.03 48.33 0.34 0.27 0.01 0.00 0.00

0.43 31.19 16.86 50.87 0.36 0.27 0.01 0.00 0.00

0.43 34.23 15.14 49.57 0.35 0.27 0.01 0.00 0.00

83.52 13.96 0.65 0.17 1.71 1.992

83.68 13.81 0.66 0.14 1.72 1.966

84.19 13.26 0.63 0.16 1.76 1.876

83.80 13.62 0.65 0.18 1.75 1.937

23.45 18.36 2.19 9.04 15.75 31.21

23.48 18.34 2.19 9.22 15.13 31.63

23.12 18.19 2.19 9.41 15.15 31.94

23.31 18.16 2.19 9.00 15.03 32.30

Composition, wt%

0.39 34.11 15.25 49.66 0.34 0.25 0.01 0.00 0.00

Elemental analysis, wt% 83.79 83.59 13.87 13.86 0.65 0.70 0.16 0.17 1.54 1.70 1.972 1.975 PIONA Analysis, wt% 23.02 23.43 18.24 18.34 1.95 2.15 9.43 9.35 15.71 15.82 31.65 30.90


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Table 4. Properties of Bottom Cuts >260°C Heavy crude oil

Upgraded oil

10.37




70356

66755

30721

31263


0.00 0.11 0.05 0.12 6.57 4.37 20.52 20.46 47.80

0.00 0.13 0.07 0.16 7.84 6.95 23.77 16.83 44.26

0.00 0.14 0.07 0.23 12.15 9.09 30.46 19.16 28.70

C H O N S H/C

82.84 9.55 1.58 0.56 5.47 1.374

81.67 11.22 1.90 0.54 4.67 1.637

81.09 11.69 1.97 0.54 4.71 1.718


Molybdenite Hematite A

Hematite B

Magnetite

13.51

13.24

13.30

13.44

32952

35788

37849

37639

0.00 0.15 0.08 0.27 11.04 8.37 29.18 19.84 31.07

0.00 0.13 0.09 0.24 10.44 8.31 29.19 19.47 32.12

0.00 0.18 0.06 0.15 10.84 8.23 27.01 19.66 33.86

0.00 0.14 0.08 0.19 10.32 7.96 27.62 20.44 33.25

81.16 11.40 1.95 0.45 5.03 1.674

81.29 11.15 1.87 0.55 5.14 1.635

81.23 11.32 1.91 0.58 4.97 1.660

Composition, wt%

0.00 0.24 0.08 0.32 11.57 8.66 29.56 19.84 29.74

Elemental analysis, wt%

81.04 11.58 1.99 0.56 4.84 1.702

81.00 11.52 1.93 0.56 4.99 1.695


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Energy & Fuels

Table 5. Properties of maltenes Heavy crude oil

Upgraded oil

17.33




143.30

106.35

66.78

67.61


0.00 0.00 0.14 0.06 0.16 8.68 5.77 27.11 27.03

0.00 0.00 0.17 0.09 0.21 10.29 9.13 31.20 22.09

0.00 0.00 0.19 0.09 0.30 15.96 11.95 40.02 25.18

C H O N S H/C

82.57 9.98 1.82 0.57 5.05 1.441

81.09 11.98 2.13 0.53 4.26 1.760

80.55 12.44 2.18 0.53 4.30 1.840


Molybdenite Hematite A Hematite B

Magnetite

22.69

22.84

22.82

22.69

71.87

72.84

72.47

72.13

0.00 0.00 0.20 0.10 0.36 14.60 11.08 38.62 26.26

0.00 0.00 0.18 0.12 0.31 13.75 10.95 38.46 25.66

0.00 0.00 0.23 0.08 0.20 14.25 10.82 35.51 25.85

0.00 0.00 0.19 0.10 0.26 13.64 10.52 36.49 27.00

80.60 12.19 2.17 0.44 4.61 1.802

80.75 11.96 2.06 0.53 4.70 1.764

80.67 12.10 2.11 0.56 4.56 1.787

Composition, wt%

0.00 0.00 0.31 0.10 0.42 15.17 11.36 38.77 26.02

Elemental analysis, wt%

80.42 12.38 2.21 0.55 4.45 1.835

80.45 12.35 2.13 0.54 4.54 1.829


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Table 6. Elemental analysis and molecular weight of asphaltenes. Heavy crude oil Density at 20°C, g/cm3

1.292

Upgraded oil Without Analytical Analytical Hematite Hematite Molybdenite Magnetite Fe2O3 catalyst MoO3 A B 1.236

1.184

1.195

1.193

1.208

1.196

1.202

Elemental analysis, wt% C

83.69

84.52

83.78

83.80

83.77

83.94

84.08

83.86

H

7.88

7.91

8.20

8.02

8.00

8.00

7.65

7.93

O

0.54

0.66

0.72

0.71

0.71

0.68

0.65

0.69

N

0.55

0.55

0.54

0.55

0.55

0.57

0.54

0.46

S

7.34

6.36

6.76

6.92

6.97

6.81

7.08

7.06

H/C

1.122

1.115

1.166

1.140

1.138

1.135

1.084

1.127

Molecular weight distribution MW

10181

9920.7

6625.7

7277.5

7131.6

7313.1

8628.9

8457.0

MN

4239.9

4226.0

3309.8

3418.8

3763.6

3785.0

3854.8

3869.2

PDI

2.40

2.32

2.78

2.42

2.31

2.28

2.29

2.43


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Table 7. Proton and 13Carbon NRM of asphaltenes. Heavy crude oil

Without catalyst

Analytical grade MoO3

Har Hα Hdα Hal Car Cal

0.1151 0.2006 0.6843 0.8849 0.3382 0.6618

0.1446 0.2151 0.6403 0.8554 0.4168 0.5832

0.166 0.243 0.591 0.834 0.4603 0.5397

n nCar nCcond Rar Rd nCal nHar nHal fa

4.3 286.22 171.44 58.39 98.52 423.82 72.93 729.26 0.4

3.82 111.15 169.56 51.79 78.9 310.3 50.66 608.06 0.5

2.11 107.55 88.99 30.44 23.77 50.19 64.47 121.78 0.69

Analytical grade Fe2O3 Proton NMR 0.166 0.244 0.590 0.834 0.4672 0.5328 13 Carbon NMR 2.16 108.71 87.94 31.38 24.01 51.94 63.94 119.81 0.68

Molybdenite

Hematite A

0.166 0.235 0.599 0.834 0.4843 0.5157

0.166 0.2295 0.6045 0.834 0.4823 0.5177

0.166 0.2152 0.6188 0.834 0.5013 0.4987

0.166 0.2235 0.6105 0.834 0.4955 0.5045

2.38 124.86 98.07 34.4 26.67 63.35 61.4 143.18 0.66

3.62 103.87 98.51 36.68 27.98 65.05 60.53 163.05 0.62

3.78 111.19 114.72 39.96 30.01 71.34 57.49 179.57 0.58

3.71 108.76 108.51 38.12 28.35 66.56 58.16 177.67 0.59


Hematite Magnetite B

Energy & Fuels

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Table 8. Interlayer spacing and microcrystalline parameters by X-ray diffraction of asphaltenes. Heavy crude oil

Upgraded oil Without Analytical Analytical Hematite Hematite Magnetite Molybdenite catalyst MoO3 Fe2O3 A B Interlayer spacing and microcrystalline parameters

X-Ray data

Microcrystalline parameter Number of aromatic sheet

2θ002, deg. 2θ100, deg. 2θ110, deg. dᵧ, Ǻ

20.48

20.71

21.44

20.96

20.85

21.18

21.59

21.20

25.30

25.30

25.56

25.23

25.21

25.26

25.15

25.21

42.62

41.53

44.47

44.70

44.64

43.67

44.66

43.48

4.34

4.29

4.14

4.24

4.26

4.19

4.12

4.19

dm, Ǻ

3.52

3.48

3.48

3.53

3.53

3.53

3.54

3.53

Lc, Ǻ

8.18

8.32

8.69

8.47

8.47

8.62

8.15

8.35

La, Ǻ

66.25

63.46

32.02

51.40

54.10

54.14

59.82

59.61

M

19.82

19.24

10.19

15.56

16.31

16.36

17.89

17.87


Page 29 of 47

Table 9. Properties of toluene insolubles. Without catalyst Feed TI

Upgrade oil Molybdenite Hematite A Fresh TI Fresh TI X-ray diffraction

Analytical MoO3 Fresh TI

Analytical Fe2O3 Fresh TI

Fe2O3 Fe1−xS α-SiO2 V2O5

Principal crystalline phases

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48

Energy & Fuels

α-SiO2 SiO2

V2(SO4)3 SiO2

MoO3

MoO3 MoS2

Fe2O3

Mo Fe O S C Si V Ni Others

0 0 53.11 0 0 46.62 0.11 0.02 0.14

0.00 0.00 20.52 3.85 54.89 15.71 0.04 0.04 4.95

66.32 0.00 33.34 0.01 0.00 0.01 0.00 0.00 0.32

45.04 0 6.08 27.87 12.98 7.75 0.02 0.02 0.24

0.00 71.3 28.6 0 0 0 0 0 0.1

MoS2 MoO2 MoO3 α-Fe2O3

MoS2 MoO2 MoO3 Fe1−xS V2O5

α-Fe2O3 Fe2+Fe3+2O4 Fe1−xS α-SiO2 SiO2

Hematite B Fresh TI

Magnetite Fresh

TI

α-Fe2O3 Fe2+Fe3+2O4 Fe1−xS V2O5 SiO2

α-Fe2O3 Fe2+Fe3+2O4 SiO2 V2O5

α-Fe2O3 Fe2+Fe3+2O4 Fe1−xS SiO2 V2O5

Fe2+Fe3+2O4 α-SiO2 Ca3(PO4)2

Fe2+Fe3+2O4 Fe1−xS Ca3(PO4)2 V2O5 SiO2

0.00 47.92 1.33 20.62 15.33 9.62 0.02 0.04 5.12

0 53.02 17.84 0.09 8.7 2.29 0.11 0.01 17.94

0.00 38.79 4.43 18.22 16.90 8.39 0.10 0.02 13.15

0 55.9 16.63 0.09 8.25 2.32 0.1 0.01 16.7

0.00 40.21 2.89 18.07 17.03 8.63 0.22 0.03 12.92

Composition by X-ray fluorescence, wt% 0.00 41.76 32.48 0 47.44 1.05 0.82 62.06 7.07 1.79 3.21 26.71 23.79 19.63 21.42 0.27 13.41 10.95 17.11 3.07 8.15 0.73 6.17 0.19 0.02 0 0.01 0 0.02 0 0.01 0.02 0.1 24.09 18.77 7.68


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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Table 10. Properties of organic fraction of toluene insolubles. Upgraded oil

C H O N S H/C MW MN PDI

Without Analytical Analytical Hematite Hematite Molybdenite catalyst MoO3 Fe2O3 A B Elemental analysis of organic fraction, wt% (CHNS/O Elemental Analyzer) 81.44 81.79 81.83 81.63 81.73 81.86 8.30 8.60 8.32 8.36 8.39 8.06 3.49 3.49 3.57 3.55 3.45 3.40 1.052 1.059 1.056 1.057 1.101 1.081 5.72 5.06 5.23 5.40 5.32 5.59 1.214 1.253 1.211 1.221 1.224 1.174 Molecular weight distribution 35298 35239 35360 35272 35217 35349 44011 44132 44041 44006 44142 44079 1.25 1.25 1.25 1.25 1.25 1.25


Magnetite 81.61 8.31 3.59 1.035 5.45 1.214 35223 44116 1.25

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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

FIGURE CAPTIONS Figure 1. General procedure for the fractionation of upgraded crude oils. Figure 2. Increase of light cuts and decrease in the distillation bottoms. (---) Light Cut, (⸺) Bottoms, (■) Without catalyst, (♦) Molybdenite, (▲) Analytical grade MoO3, (○) Hematite B, (□) Magnetite, ( ) Hematite A, (●) Analytical grade Fe2O3. Figure 3. Variation in the content of sulfur of light cuts and distillation bottoms. (---) Light Cut, (⸺) Bottoms, (■) Without catalyst, (♦) Molybdenite, (▲) Analytical grade MoO3, (○) Hematite B, (□) Magnetite, ( ) Hematite A, (●) Analytical grade Fe2O3. Figure 4. Change in the distillation fractions of light cuts. ( ) LSRN, ( ) MSRN, ( ) HSRN, ( ) JF, ( ) K, ( ) SRGO, ( ) LVGO. Figure 5. Increase in the content of PIONA fractions of light cuts. ( ) Paraffins, ( ) Isoparaffins, ( ) Naphthenes, ( ) Olefins, ( ) Aromatics, ( ) Unidentified. Figure 6. Increase in the content of fractions of the distillation bottoms. ( ) MSRN, ( ) HSRN, ( ) JF, ( ) K, ( ) SRGO, ( ) LVGO. Figure 7. Reduction of HGVO and conversion of vacuum residue in the distillation bottoms. (■) Without catalyst, (♦) Molybdenite, (▲) Analytical grade MoO3, (○) Hematite B, (□) Magnetite, ( ) Hematite A, (●) Analytical grade Fe2O3. Figure 8. Reduction of the asphaltenes content. (■) Without catalyst, (♦) Molybdenite, (▲) Analytical grade MoO3, (○) Hematite B, (□) Magnetite, ( ) Hematite A, (●) Analytical grade Fe2O3. Figure 9. Reduction in the content of sulfur in the maltenes. (■) Without catalyst, (♦) Molybdenite, (▲) Analytical grade MoO3, (○) Hematite B, (□) Magnetite, ( ) Hematite A, (●) Analytical grade Fe2O3. Figure 10. Increase in the distillation fractions in the maltenes. ( ) LSRN, ( ) MSRN, ( ) HSRN, ( ) JF, ( ) K, ( ) SRGO, ( ) LVGO. Figure 11. Reduction of HGVO and conversion of vacuum residue in the maltenes. (■) Without catalyst, (♦) Molybdenite, (▲) Analytical grade MoO3, (○) Hematite B, (□) Magnetite, ( ) Hematite A, (●) Analytical grade Fe2O3. Figure 12. Reduction in the content of sulfur of asphaltenes. (■) Without catalyst, (♦) Molybdenite, (▲) Analytical grade MoO3, (○) Hematite B, (□) Magnetite, ( ) Hematite A, (●) Analytical grade Fe2O3. Figure 13. Amount of coke in the toluene insolubles. Figure 14. Amount of recovered active metal.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Figure 15. X-ray diffraction of Fe2O3 analytical grade catalyst, magnetite catalysts and toluene insolubles of the heavy crude oil, upgraded oil without catalyst and upgraded oil with Fe2O3 analytical grade and magnetite catalysts


Page 32 of 47

Page 33 of 47

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Crude Oil Atmospheric distillation Light cuts

Characterization of Upgraded Oil Fractions Obtained by Slurry-Phase

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