A Study of the Catalytic Steam Cracking of Heavy Crude Oil in the ...

ISSN 0965-5441, Petroleum Chemistry, 2017, Vol. 57, No. 7, pp. 618–629. © Pleiades Publishing, Ltd., 2017. Original Russian Text © O.O. Mironenko, G.A. Sosnin, P.M. Eletskii, Yu.K. Gulyaeva, O.A. Bulavchenko, O.A. Stonkus, V.O. Rodina, V.A. Yakovlev, 2017, published in Nanogeterogennyi Kataliz, 2017, Vol. 2, No. 1, pp. 74–87.

A Study of the Catalytic Steam Cracking of Heavy Crude Oil in the Presence of a Dispersed Molybdenum-Containing Catalyst O. O. Mironenkoa, *, G. A. Sosnina, b, P. M. Eletskiia, Yu. K. Gulyaevaa, O. A. Bulavchenkoa, b, O. A. Stonkusa, b, V. O. Rodinaa, and V. A. Yakovleva aBoreskov

Institute of Catalysis, Siberian Branch, Russian Academy of Sciences, Novosibirsk, Russia bNovosibirsk State University, Novosibirsk, Russia *e-mail: [email protected] Received January 15, 2017

Abstract⎯The features of the steam cracking of heavy crude oil in the presence of a dispersed molybdenumcontaining catalyst are studied. The effect of water, the catalyst, and process conditions on the composition and properties of the products of the thermal conversion of heavy crude oil is determined in experiments on thermal cracking, steam cracking, catalytic cracking in the absence of water, and hydrocracking. A complex analysis of the resulting products is conducted; the catalyst-containing solid residue (coke) has been studied by XRD and HRTEM. The effect of the process temperature (425 and 450°C) and time on the yields and properties of the resulting products is studied. The efficiencies of hydrocracking and steam cracking for the production of upgraded low-viscosity semisynthetic oil are compared; the fundamental changes that occur in the catalyst during the studied processes are discussed. Some assumptions about the principle of the catalytic action of the molybdenum-containing catalyst in the steam cracking process are made. Keywords: dispersed catalyst, molybdenum, heavy crude oil, catalytic steam cracking DOI: 10.1134/S0965544117070088

The growing global demand for motor fuels necessitates a significant increase in the use of heavy oil feedstocks (HOFs), such as high-sulfur heavy crude oils, natural bitumen, and heavy residual oil fractions (e.g., vacuum residue, fuel oil), in oil refining. This feedstock is characterized by a high viscosity and a high content of sulfur, metals, and asphaltic–resinous components with a high concentration of nitrogenand oxygen-containing organic compounds and, conversely, with a low or zero content of light hydrocarbon fractions [1]; therefore, it is difficult to handle this feedstock both at the stage of extraction and during transportation and further processing. Thus, the development of approaches to upgrading HOFs, particularly to decreasing the viscosity, is an urgent and significant problem [2]. Modern technologies for processing heavy crude oils and residual fractions are aimed at converting HOFs to lighter low-viscosity semisynthetic (the product of HOF pretreatment) and synthetic oils (distilled petroleum fractions derived from semisynthetic oil). The best-known approaches to HOF processing involve the use of thermal and catalytic cracking, which lead to the removal of excess carbon; hydrogenation processes with the introduction of additional hydrogen; or a combination of these approaches [3, 4]. The processes based on a decrease in the carbon con-

tent in the feedstock (thermal/thermocatalytic cracking) are characterized by a lower resource intensity than that of hydrogenation processes; however, they lead to a decrease in the yield of valuable light hydrocarbon fractions. The use of hydrogen in hydrogenation processes leads to the suppression of coke formation and to an increase in the yield of hydrogen-saturated liquid fractions; therefore, the commercial significance of the resulting product increases. However, the use of hydrogen to solve the problem of pipeline transportation of heavy crude oil directly at the extraction sites is difficult and costly. On the other hand, the use of hydrogenation processes to decrease the viscosity of this feedstock is efficient because improvement in the properties of the resulting product provides a decrease in the load on the major units of refineries. However, the hydrogen technologies require significant capital investments; this fact stimulates the search for other technological approaches to HOF processing without the use of gaseous hydrogen. In recent years, the number of reports describing approaches based on thermal and thermocatalytic conversions of HOFs in the presence of water has been steadily increasing. With respect to reaction conditions and, accordingly, the type of occurring chemical processes, these approaches can be conventionally

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divided into aquathermolysis and steam cracking. Aquathermolysis is understood as the conversion of oil components under the action of steam in the simulation of conditions of a heated reservoir, under which the apparent temperature can achieve a value higher than 200°C. However, in most cases, the aquathermolysis temperature does not exceed 320°C [5–17]. It is believed that, under the action of steam and heat, the following chemical conversions can occur: hydrolysis of ether, sulfide, and amine bridges; thermocracking of heteroatomic compounds and polycyclic aromatic hydrocarbons; hydrogen redistribution; hydrogenolysis of heteroatomic compounds; and hydrocracking of polycyclic aromatic hydrocarbons involving hydrogen produced during the conversion of carbon oxide under the action of steam [14]. These processes lead to a decrease in viscosity, formation of a lighter hydrocarbon composition, and decrease in the content of heteroatoms in the resulting products. In addition, the use of water in thermal conversions of heavy crude oils compensates for hydrogen deficiency and, thereby, leads to a decrease in coke formation; as a consequence, the yield of target products increases [2, 5, 15]. In general, aquathermolysis has proven itself to be a promising method for decreasing viscosity with a decrease in the resin content to 55% of the initial amount; however, the low temperatures of this process do not provide a significant conversion of asphaltenes even in the presence of catalysts based on a broad range of transition metals (Ni, Co, Cu, Fe, etc.) because of low equilibrium constants of C–C bond cracking and a low process rate in the absence of a catalyst [7]. Furthermore, under these conditions, the interaction of water and hydrocarbons is also insufficient; therefore, it is necessary to use higher temperatures. An increase in temperature to 350°C or above leads to the occurrence of C–C bond cracking and thereby provides a more significant decrease in the average molecular weight of the oil components and an increase in the water–gas shift reaction rate. Thus, at high temperatures, in addition to the reactions that occur via heteroatoms during aquathermolysis, the activation of “complete” thermal (or catalytic) cracking and a significant water–feedstock interaction are observed; owing to these features, the process time can be reduced from a few tens of hours to a few minutes. Under these conditions, water acts not only as a solvent and a catalyst for the hydrolysis of heteroatom compounds [7] but also as an inhibitor of coke formation owing to the blocking of hydrocarbon radicals. The result is a deeper and more vigorous conversion of heavy components of the oil feedstock, which is necessary for the above decrease in the load on the refinery’s units [18, 19]. In the literature, HOF upgrading at 350–550°C in the presence of water in the state of superheated steam is referred to as steam cracking. This process is implePETROLEUM CHEMISTRY

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mented both in the presence and in the absence of catalysts [20]. The mechanisms of direct interaction of water with hydrocarbons/hydrocarbon radicals under process conditions are currently controversial. In general, the authors mention the formation of hydrogen by the water–gas shift reaction (СО + Н2О → СО2 + Н2) or refer to the interaction of water with hydrocarbon radicals without revealing the features of the mechanism. There are some published estimates of the possible interaction of water with hydrocarbons or radicals at low temperatures. The author of [21] describes the results of thermodynamic calculations of the reaction between water and hydrocarbon radicals in a temperature range of 20–374°C. The thermodynamic data for radicals were taken for gas-phase reactions because there are no thermodynamic data for liquid-phase processes. It was shown that the saturation of hydrocarbon radicals involving water is thermodynamically possible in accordance with the following schemes characterized by the formation of aldehydes, alcohols, alkanes, and hydrogen/oxygen as intermediates:

C nH i2n + 1 + H 2O C nH 2nO + 1.5H 2,

C nH i2n + 1 + H 2O C nH 2n + 1OH + 0.5H 2, C nH i2n + 1 + H 2O C nH 2n + 2 + 0.5O 2. Thus, the interaction of hydrocarbon radicals can result in the formation of atomic hydrogen, which subsequently can also saturate the radicals or be involved in the hydrogenation/hydrocracking of hydrocarbons. In addition to processes involving radicals, hydrogen can also be formed during the reaction of water with hydrocarbons according to the scheme of the socalled low-temperature partial steam reforming [22]: (СН2)х + хН2О → 0.5хСН4 + 0.5хСО2 + хН2. It is noted that this process at 450–500°C can occur only in the presence of high-activity catalysts. The use of catalysts in steam cracking makes it possible to increase the efficiency of the thermal conversion of oil feedstocks and, as a consequence, to improve the quality of semisynthetic and/or synthetic oil. In some cases, it is possible to suppress the coke formation process up to the absence of coke in the reaction products [23]. The authors of reports on the steam cracking of hydrocarbon feedstocks generally describe the use of four types of catalysts: (i) dispersed catalyst systems based on nickel with particle sizes of 1–100 nm [2, 24–27]; (ii) coarsely dispersed oxidation catalysts based on iron(III) oxide prepared by coprecipitation with particle sizes of more than 10 μm [12, 23, 28]; (iii) supported catalysts with supports of different nature [29–32]; and (iv) rock-forming minerals (hematite, silica gel, bentonite, kaolin) [33, 34]. It should be noted that the catalytic steam cracking process flow sheet and the properties of the resulting products depend on the catalyst type.

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Table 1. Physicochemical properties of the heavy crude oil Elemental composition С Н N S Fractions, °C IBP–200 200–350 350–500 Above 500 Н : С atomic ratio Density, g/cm3

Content, wt % 83.8 12.1 0.7 4.3 Content, wt % 0 21 31 48 1.74 0.96 2825

Kinematic viscosity at 25°C, mm2/s

There is hardly any information on the use of Mocontaining catalysts in the catalytic steam cracking of HOFs; however, these catalysts are commonly used in hydrotreatment and hydrocracking processes. Among the above catalyst systems, emphasis should be put on the dispersed catalysts of the first type, which are prepared in situ under reaction conditions. Thus, the authors of [35] showed the efficiency of an ultrafine molybdenum-containing catalyst in hydrocracking at a high hydrogen pressure (8–16 MPa). This catalyst is formed in situ in the oil feedstock from reverse emulsions of solutions of precursor salts of the active component of the catalyst; this feature provides a high conversion of the oil feedstock (up to 90 wt %) using hydrogen. In general, the dispersed nature of a catalyst prepared in situ under reaction conditions provides a decrease in diffusion hindrances during mass transfer and pore blocking by coke deposits [36]. Therefore, according to the results obtained with the use of in situ

synthesized dispersed molybdenum catalysts for HOF upgrading in the presence of hydrogen, it is reasonable to expect that these systems will be efficient in catalytic steam cracking. This study is focused on the features of the catalytic steam cracking of heavy crude oil from the oil fields of the Republic of Tatarstan in a batch mode in the presence of a dispersed Mo-containing catalyst. EXPERIMENTAL In this study, heavy crude oil (the Republic of Tatarstan) with a high content of sulfur—4.3 wt %— and high-boiling fractions (>500°C)—48 wt %—was used (Table 1). The catalytic steam cracking of crude oil was studied using an Autoclave Engineers autoclave system (Parker, United States) with a reactor volume of 1 L. The process was studied at temperatures of 425 and 450°C under continuous stirring (1000 rpm). The initial pressure in the reactor corresponded to atmospheric pressure (STP) and achieved a value of 13.9– 19.2 MPa during crude oil conversion in the presence of water and 5.6 MPa in the tests in the absence of water. In the hydrocracking reaction, the initial hydrogen pressure in the system was 6.0 MPa and achieved 12.7 MPa. The test time was varied from 15 to 60 min. In the studies, 150 g of crude oil and 45 g of water were used. The parameters of all the tests and their designations are shown in more detail in Table 2. The catalyst was introduced into oil during preparation of reverse emulsions. An aqueous solution of the precursor— ammonium heptamolybdate ((NH4)6Mo7O24 · 4H2O)— was added to a required amount of crude oil to provide the maximum degree of dispersion of the resulting catalyst in the feedstock dispersion. The precursor concentration in the emulsion in terms of the metal was 2.0 wt %; the water and surfactant concentrations were 11 and 5 wt %, respectively. To provide a high degree of dispersion of catalyst par-

Table 2. Conditions for tests on the thermal upgrading of heavy crude oil Process Thermal cracking

Temperature, °C

Time

425

1h

Maximum pressure, MPa 4.0

Steam Cracking Catalytic steam cracking*

13.9 425 450

30 min

14.0

1h

14.5

15 min

16.4

1

19.2

Catalytic cracking*

425

1

5.6

Hydrocracking*

425

1

12.6

450

12.7

* In the presence of a 2% Mo-containing catalyst. PETROLEUM CHEMISTRY

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ticles, nonionic surfactant SPAN 80 (a hydrophilic– lipophilic balance of 4.3) was used; it is a stabilizer of reverse emulsions [37]. Crude oil, an aqueous solution of the catalyst precursor, and the surfactant were mixed using a disperser (IKA T-25 basic ULTRATURRAX) at a speed of 24000 rpm for 3 min. The resulting reverse emulsion of the aqueous solution of the catalyst precursor in oil was subjected to thermal decomposition in an autoclave system at atmospheric pressure and a temperature of 210°C (process time, 1 h; heating rate, 6.3°C/min). Upon completion of the decomposition process (cessation of the condensation of water and the catalyst precursor decomposition products in the trap located at the outlet of the reactor), the heating was turned off and the reactor was cooled with compressed air. After the addition of water or feeding hydrogen to the resulting feedstock dispersion, the reactor was sealed and pressurized with argon at a pressure of 10 MPa. After that, the system was purged with argon to expel the residual air. In the case of hydrocracking, hydrogen was supplied to the system after pressurizing with argon. Next, the system was heated to a target temperature at a rate of 5°C/min. After the test, the reactor was cooled with compressed air. Analysis of gaseous incondensable products (C1– C4 hydrocarbons, hydrogen, CO, CO2) was conducted by gas chromatography on a KhROMOS GKh-1000 gas chromatograph (Russia) equipped with 3 m × 2 mm packed columns (silochrome and activated carbon), a thermal conductivity detector, and a flame ionization detector using argon as a carrier gas. The mixture of liquid products, petroleum coke, and water was exhaustively removed from the reactor. After settling, most of the liquid products were decanted, while the remaining portion of the liquid products and high-boiling fractions mixed with coke were extracted with excess dichloromethane. To minimize losses of products of the process, the autoclave system was thoroughly washed with dichloromethane. After that, the mixture of hydrocarbons in dichloromethane and water was filtered off from coke; the solid residue was washed on a Schott glass filter (porosity S2) in vacuum using a Bunsen flask. The filtered mixture of water and the liquid product solution in dichloromethane was separated on a separatory funnel. Dichloromethane was distilled from the resulting solution of liquid products using a rotary evaporator. The resulting portion of the products was mixed with the mixture decanted at the previous stage. The CHNS elemental composition of the feed heavy crude oil and the cracking products was determined using a VARIO EL CUBE CHNS+O analyzer (Elementar Analysensysteme, Germany). Each of the samples was analyzed at least three times with subsequent averaging of the results. The fractional compositions of the heavy crude oil and the mixed liquid products of oil conversion were PETROLEUM CHEMISTRY

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determined by fractionation using a semiautomatic instrument intended for the fractionation of heavy and residual petroleum products (B/R Instrument Corp., United States). Analysis was conducted in accordance with the ASTM-1160 standard. The kinematic viscosity of the feed heavy crude oil and the cracking products was determined using VNZh3.41, VNZh0.61, and VNZh0.8 reverse-flow calibration viscometers at 25°C in accordance with Russian State Standard GOST 33-2000. The density of the feed heavy crude oil and the liquid products of oil conversion was determined using a PZh3-1-25 pycnometer in accordance with GOST 3900-85. At each measurement, the pycnometer filled with the analyte was thermostated at a temperature of 25°C. The ash content in the coke was determined as described in [38]; according to the technique, a catalyst-containing coke sample was combusted in a muffle furnace at a temperature of 550°C in an air atmosphere for 3 h. The X-ray powder diffraction (XRD) analysis of the solid residue was conducted after the process on a D8 Advance diffractometer (Bruker, Germany) equipped with a Lynxeye (1D) linear detector using monochromatized CuKα radiation (λ = 1.5418 Å). XRD patterns were recorded in a 2θ angle range of 10°–80° in increments of 0.05° at an acquisition time per point of 2 s. The average coherent scattering regions (CSRs) were calculated by the Selyakov– Scherrer formula from the half-width of the diffraction lines [39]. After the tests, the catalyst-containing coke samples were studied by high-resolution transmission electron microscopy (HRTEM) on a JEM-2010 transmission electron microscope (JEOL, Japan) at an accelerating voltage of 200 kV and a resolution of 0.14 nm. Sample particles were deposited by dispersing a sample suspension in alcohol on an aluminum substrate using an ultrasonic disperser. RESULTS AND DISCUSSION A compound based on molybdenum (ammonium heptamolybdate), which is one of the metals most commonly used in the hydroprocessing of oil feedstocks, was selected as a catalyst precursor to study the catalytic steam cracking process (CSC) [39]. To determine the effect of water, the presence of a catalyst, and the process conditions on the composition and properties of the products of the thermal conversion of heavy crude oil, tests on thermal cracking, steam cracking, catalytic cracking in the absence of water, and hydrocracking were conducted. The efficiency of the process was determined from the total yield of light fractions (Тboil < 350°C), synthetic oil (fractions with Тboil < 500°C), semisynthetic oil (liquid products in general), petroleum coke, and gaseous products. In

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addition, the H : C atomic ratio, sulfur content, viscosity, and density were estimated. The results are summarized in Table 3. Table 3 shows that the introduction of water into the process leads to a slight increase in the yield of light fractions from 47% (thermal cracking) to 50 and 51% (steam cracking and catalytic steam cracking, respectively (425°C, 1 h)). Compared with uncatalyzed steam cracking (425°C, 1 h), catalytic steam cracking leads to an increase in the H : C ratio in the liquid products to 1.70, whereas in the case of catalytic cracking in the absence of water, the H : C ratio decreases to 1.62. This result suggests that, in the presence of the catalyst, the hydrogen transfer from water to liquid products is more vigorous both in reaction with hydrocarbon radicals and in low-temperature partial steam reforming [22]. In addition, the use of the Mo-containing catalyst leads to an increase in the H : C ratio owing to the intensification of hydrogenation/hydrocracking processes. With a decrease in the catalytic steam cracking time from 1 h to 30 min, the coke yield decreases, while the yield of liquid products increases both owing to highboiling fractions that are not converted to coke and remain in the liquid products and owing to a decrease in losses during the post-treatment of products of the process. The H : C ratio decreases; this finding can be attributed to the kinetic features of the processes concerning the water–feedstock interaction: apparently, at 425°C, water does not exhibit high chemical activity and the processes involving water require a longer time or a significant increase in the water to feedstock ratio, which is impossible in the batch mode because of engineering constraints. In addition, the decrease in the H : C ratio can be associated with the contribution of high-boiling fractions—coke precursors—that remain in the liquid products because the hydrogen content in them is lower than that in lighter hydrocarbon fractions. With an increase in the catalytic steam cracking temperature to 450°C, the yield of liquid products decreases, while the coke yield increases; this finding is attributed to intensification of the coke formation process. In addition, an increase in the yield of gaseous products is observed in the tests. According to the set of parameters characterizing the composition and yield of products of heavy crude oil conversion, it can be concluded that catalytic steam cracking at a temperature of 425°C is efficient. For comparison with catalytic steam cracking, tests on hydrocracking were additionally conducted. In the case of hydrocracking, the yield of liquid products increased, and the yield of light hydrocarbons did not change, while the H : C ratio increased compared with the respective parameters of catalytic steam cracking under the same conditions. With an increase in the process temperature to 450°C, the yield of liquid products decreased mostly owing to a decrease in the bal-

ance yield and an increase in the yield of gaseous products. In this case, the yield of light hydrocarbons increased and the H : C ratio was 1.82. This change in the ratio of products and their properties is attributed to the intensification of the hydrocracking and hydrogenation processes. According to the results of comparison of catalytic steam cracking and hydrocracking at different temperatures, the following differences in the features of interaction of water and hydrogen with the feedstock can be assumed. Under these oil upgrading conditions, water, unlike hydrogen, does not exhibit high reactivity, particularly in the generation of atomic hydrogen, which is active in the inhibition of hydrocarbon radicals. It is reasonable to expect an increase in the efficiency of using water in the case of increase in the water to feedstock ratio or optimization of process parameters and catalyst composition. Analysis of the liquid products of catalytic steam cracking (425°C, 1 h) showed an approximately 500-fold decrease in viscosity compared with that of the feed crude oil. In the case of hydrogen-free processes, the viscosity of the liquid products mostly depends on the process temperature and time and weakly depends on the introduction of water/catalyst into the process. A decrease in the density from 0.96 (feed crude oil) to 0.91–0.94 g/cm3 (reaction products) was observed. In the case of hydrocracking at 425°C, the viscosity of the liquid products decreased to 13.8 mm2/s at 25°C, while the density was 0.89 g/cm3. With an increase in the hydrocracking temperature to 450°C, the viscosity of the products decreased to 2.7 mm2/s, while the density of the semisynthetic oil was 0.86 g/cm3. The observed decrease in the viscosity and density of the resulting semisynthetic oil is attributed to a change in the oil composition caused by respective processes. The high viscosity of the product formed during hydrocracking at 425°C (13.8 mm2/s) compared with the product of steam cracking at the same temperature (5.2 mm2/s) can be explained by the different nature of chemical conversions. During hydrocracking, the resulting intermediates of large molecules are saturated with hydrogen to produce high-boiling fractions which increase the viscosity of the product; in the case of steam cracking, the intermediates are converted to coke deposits; they do not make the fractional composition heavier and, therefore, do not increase the viscosity of the liquid products. An increase in the hydrocracking temperature to 450°C leads to an increase in the yield of light hydrocarbons, which results in a decrease in the viscosity and density of the resulting liquid products. The CHNS analysis revealed that, in all the processes, the sulfur content in the liquid products decreases and sulfur is partially concentrated in the solid residue. The results in Table 4 show that, during catalytic steam cracking in the presence of a Mo-containing catalyst, the sulfur content in the liquid products decreases more dramatically than it does in the PETROLEUM CHEMISTRY

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1.61 5.1

–

– 100 1.74 2825

0.96

Coke yield after subtraction of ash content

Gas

Balance

Н : С ratio in liquid products

Kinematic viscosity of semisynthetic oil at 25°C, mm2/s

Density of liquid products, g/cm3

0.93

93

2

8

83

100

Semisynthetic oil (total amount of liquid products)

65

47

52

21

thermal cracking Т = 425°C, t = 1 h

Synthetic oil (fractions with Тboil < 500°C)

Light fractions (Тboil < 350°C)

Parameters

Feed heavy crude oil, wt % uncatalyzed steam cracking, Т = 425°C, t = 1 h 0.91

6.3

1.64

91

2

7

82

64

50

catalytic steam cracking, Т = 425°C, t = 1 h, m(H2O) = 45.0 g 0.93

5.2

1.70

93

3

8

82

66

51

0.94

4.3

1.62

93

3

8

82

61

48

catalytic cracking, Т = 425°C, t=1h Т = 425°C, t = 30 min 0.93

16.3

1.62

98

2

3

93

69

50

Т = 450°C, t = 15 min 0.90

3.2

1.68

91

4

13

74

63

55

0.87

2.3

1.66

85

6

20

58

52

46

Т = 450°C, t=1h

hydrocracking, P(Н2) = 6.0 MPa

0.89

13.8

1.79

97

2

2

93

75

51

Т = 425°C, t=1h

catalytic steam cracking, m(H2O) = 45.0 g

0.86

2.7

1.82

91

4

2

86

76

64

Т = 450°C, t=1h

Yield, wt %

Table 3. Yield and properties of the heavy crude oil conversion products in the presence of a 2 wt % Mo-containing catalyst (mheavy oil = 150 g)

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Table 4. Sulfur content in the liquid products and coke formed during heavy crude oil conversion

catalytic steam cracking, Т = 425°C, t = 1 h, m(H2O) = 45.0 g

catalytic cracking, Т = 425°C, t = 1 h

Т = 425°C, t = 30 min

Т = 450°C, t = 15 min

Т = 450°C, t=1h

Т = 425°C, t=1h

Т = 450°C, t=1h

Coke

uncatalyzed steam cracking, Т = 425°C, t = 1 h

Liquid products


Test object

feed heavy crude oil, wt %

Sulfur content, wt %

4.3

3.5

3.3

2.8

2.8

3.2

2.6

2.6

2.3

1.7

0

6.4

6.3

6.6

12

6.6

6.2

6.1

28

31

thermal and steam cracking processes. Catalytic steam cracking at 425°C leads to a significant decrease in the sulfur content in coke (from 12.0 wt % for catalytic cracking in the absence of water to 6.6 wt % for catalytic steam cracking), while the sulfur content in the liquid products remains unchanged. This result suggests that water is involved in the catalytic hydrolysis of sulfur-containing hydrocarbons with the subsequent conversion of sulfur into gaseous products. In the case of hydrocracking, the high sulfur content in the solid residue is attributed to the following factors: the Mo-containing phase undergoes almost complete sulfiding; the coke yield is extremely low; and the solid residue mostly comprises a sulfided Mo-containing phase. In the case of catalytic cracking, the coke yield is comparable to that in catalytic steam cracking; however, in this case, sulfur also accumulates owing to sulfiding of the Mo-containing phase in the absence of water. According to these data, the following schematic desulfurization in the presence of steam can be assumed (Fig. 1). Table 5 shows the reactions involving sulfur compounds that occur in the studied heavy crude oil conversion processes. Comparison of the sulfur content in S-containing hydrocarbons MoO2

MoS2

-H2S

H2O

Fig. 1. Assumed schematic catalytic conversion of sulfurcontaining hydrocarbons by catalytic steam cracking in the presence of the molybdenum-containing catalyst.



the liquid products and coke in the different processes (Table 4) and the reactions occurring in them (Table 5) makes it possible to determine the contribution of each of the reactions to the feedstock desulfurization. A сomparison of thermocracking and steam cracking reveals that the degree of desulfurization increases owing to the occurrence of hydrolysis of the C–S bonds of the hydrocarbons. During catalytic steam cracking, desulfurization is deeper than that in the case of steam cracking (decrease in the sulfur content in the liquid products) because of catalytic hydrolysis and the formation of MoS2. It is known [41] that the total pressure of gases hinders the formation of gaseous products during the thermal conversion of hydrocarbons. The high pressure of catalytic steam cracking (14.5 MPa) compared with the pressure of catalytic cracking in the absence of water (5.6 MPa) can hinder the formation of sulfur-containing gaseous products. The addition of water, on one hand, leads to the suppression of thermal desulfurization owing to an increase in pressure and, on the other hand, provides the catalyst reactivation (Fig. 1). Thus, the occurrence of opposing processes leads to the identical sulfur content in the liquid products of catalytic cracking in the presence and in the absence of water. A switch from a batch reactor to a flow mode (slurry reactor) will make it possible to intensify the desulfurization process owing to a decrease in the total pressure in the system. During the hydrocracking of heavy crude oil, the decrease in the sulfur content in semisynthetic oil is more dramatic than that in the case of catalytic steam cracking. At 450°C, an intensification of desulfurization is observed: the sulfur content in the semisynthetic oil decreases from 4.3 wt % in the feed product to 1.7 wt %. Similar results were obtained in [35], where after hydrocracking in a f low reactor, the sulfur content decreased from 4.08 wt % (feed fuel oil) to 1.60 wt % at a catalyst content of 0.05 wt %. In this study, a larger catalyst content (2 wt %) was used in a batch mode to obtain a similar degree of desulfurPETROLEUM CHEMISTRY

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Table 5. Reactions involving sulfur compounds in the thermal conversion of heavy crude oil (T = 425°C, t = 1 h) Thermal cracking

Steam cracking

Catalytic cracking

Catalytic steam cracking

Thermal desulfurization

+

+

+

+

An increase in S content in the gas

Formation of MoS2

–

–

+

+

An increase in S content in the coke

Catalytic hydrolysis

–

–

–

+


Hydrolysis

–

+

–

+


in the liquid phase

3.5

3.3

2.8

2.8

in the coke

6.4

6.3

12

6.6

Reaction

Sulfur content, wt %

Result

Table 6. Composition of the gaseous products of heavy crude oil conversion

uncatalyzed steam cracking, Т = 425°C, t = 1 h

catalytic steam cracking, Т = 425°C, t = 1 h, m(H2O) = 45.0 g

catalytic cracking, Т = 425°C, t = 1 h

Т = 425°C, t = 30 min

Т = 450°C, t = 15 min

Т = 450°C, t=1h

Т = 425°C, t=1h

Т = 450°C, t=1h

Component of the gas phase of reaction products


Content, wt %

5 0 0 58 37

3 0.6 0 53 44

9 0.2 7 51 33

9 1 3 61 26

12 0.3 9 47 32

12 0.5 7 55 26

7 0.2 4 63 26

58 0 0 9 33

44 0 0 25 31

H2 CO CO2 С1–С4 Unidentifiable hydrocarbons, N- and S-containing compounds, including H2S

ization; this fact can be attributed to different conditions for the catalyst preparation and the hydrocracking process, particularly different types of feedstock. Analysis of the composition of the gaseous products of steam cracking (Table 6) showed that, in the presence of the catalyst, the hydrogen concentration increases and the formation of CO2 is observed. The CO concentration remains low almost in all cases; this finding indicates intensification of CO oxidation by water under the action of catalysts (water-gas shift reaction). The results suggest that, during catalytic steam cracking in the presence of Mo-containing catalysts, the sulfur content in the coke and in the liquid phase decreases owing to desulfurization as a consequence of evolution of gaseous sulfur-containing products. The absence of CO and CO2 in hydrocracking processes can be attributed to both the hydrogenaPETROLEUM CHEMISTRY

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tion of the feed oxygen-containing compounds and the direct hydrogenation of carbon oxides in the gas phase. The HRTEM studies of the condensation products of catalytic steam cracking in the presence of the Mocontaining catalyst (Fig. 2a) revealed that molybdenum is in the form of two phases—MoO2 particles and agglomerates (20–100 nm) and single- and doublelayer linear MoS2 particles with a length of 10–15 nm— in an amorphous carbon matrix. It should be noted that MoS2 is located both in direct contact with molybdenum oxide particles and at a distance from them. The HRTEM studies did not reveal any significant differences in coke deposits formed during catalytic steam cracking at 425°C (1 h) and 450°C (15 min). In the case of catalytic steam cracking at 450°C (1 h), in addition to the MoO2 particles and

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(a) MoS2 MoS2

MoO2

MoO2

C

C 100 nm

50 nm

(b) C

C MoS2 MoS2

50 nm

10 nm

Fig. 2. TEM images of the coke residue samples with a dispersed Mo-containing catalyst after the test on catalytic cracking at 425°C: (a) in the presence and (b) in the absence of water.

agglomerates, the presence of a small amount of a molybdenum sulfide phase composed of linear MoS2 particles with 1–4 layers and a length of 10–15 nm is observed. In catalytic cracking in the absence of water (Fig. 2b), the fraction of the MoS2 phase increases, as evidenced by the CHNS analysis data. In this case, the presence of particles with 1–3 layers and a length of 7–10 nm is observed. In addition, the TEM images show high-contrast regions (marked with white circles), which correspond to the molybdenum oxide phase with a weakly ordered structure. The Mo-containing phase of the coke deposits after hydrocracking (Fig. 3) is composed almost entirely of MoS2 particles; this structure is typical of the hydrocracking of heavy crude oil in the presence of Mo-containing catalysts. It should be noted that, in the case of hydrocracking at a temperature of 425°C, molybdenum sulfide particles with a thickness of 4–6 layers and a length of 10–20 nm are observed. In the sample of the coke residue of hydrocracking at 450°C, the amount of

molybdenum sulfide is larger; it covers the entire surface; the layer thickness is 2–3 nm and the length is 5– 15 nm. In addition, there are high-contrast regions (marked with white circles), which apparently correspond to noncrystallized MoOx particles. The XRD patterns (Fig. 4) of the samples of coke residues after catalytic steam cracking exhibit several reflections at 2θ = 26.0°, 33.0°, 36.5°, 41.6°, 49.5°, 53.5°, 60.5°, 66.9°, and 72.9° corresponding to interplanar distances of 3.42, 2.67, 2.43, 2.17, 1.84, 1.71, 1.53, 1.4, and 1.3 Å. According to [PDF # 32–671], these peaks are ascribed to the MoO2 phase. The average CSR sizes of the MoO2 phase for the studied samples were 340–360 Å, as determined with respect to the –111 reflection. In addition, the XRD patterns exhibited small broadened peaks at 2θ = 33.5° and 58.5°, which did not correspond to the molybdenum oxide phase. The intensity of the peaks significantly increases in the sample of coke residue of catalytic cracking (425°C, 1 h) and corresponds to the MoS2 PETROLEUM CHEMISTRY

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(a)

MoS2

MoS2

20 nm

20 nm

(b)

MoS2

MoS2

20 nm

20 nm

Fig. 3. TEM images of the coke residue samples with the dispersed Mo-containing catalyst after hydrocracking at (a) 425 and (b) 450°С.

phase. According to HRTEM, the catalytic steam cracking conditions do not lead to the formation of well-crystallized phases of molybdenum sulfide. This finding is attributed to the fact that the water involved in the process shown in Fig. 1 hinders the formation of well-crystallized phases of MoS2. The XRD pattern of the sample of solid residue (coke) formed during catalytic cracking in the absence of water (Fig. 4, line d) exhibits several broad peaks located at 2θ = 25.6°, 33.5°, 36.9°, 53.4°, and 59.3° (d = 3.49, 2.65, 2.42, 1.72, and 1.55 Å). The reflections with interplanar distances of d = 3.49, 2.42, and 1.72 Å correspond to the MoO2 phase; the remaining peaks are ascribed to the MoS2 sulfide [PDF 37-1492]. In addition, a broad halo at 2θ = 23.0°–28.0° is observed; it can be attributed to the presence of carbon. The XRD pattern of the sample of solid residue (coke) formed during hydrocracking at 425°C (Fig. 4, PETROLEUM CHEMISTRY

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line e) exhibits, along with broad peaks corresponding to the MoS2 phase, several small reflections corresponding to MoO2 particles. The XRD pattern of the sample of coke residue formed during hydrocracking at a temperature of 450°C (Fig. 4, line f) slightly differs from the XRD pattern of the sample formed at 425°C: narrow reflections of MoO2 are absent; only broad halos corresponding to MoS2 are observed. The average CSR sizes of the MoS2 phase were 30–35 Å, as determined with respect to the 002 reflection. Thus, the XRD data confirm the formation of a significant amount of molybdenum sulfide during the HOF hydrocracking; this finding is consistent with the relevant published data [35, 42, 43]. The XRD data for coke deposits formed during the tests showed that the observed molybdenum sulfide phase most probably has a hexagonal crystal lattice. This modification of MoS2 can be represented as a lay-

MIRONENKO et al. –111

628

V V

*

20

30

–310 031 013

202 –402 –204

–411 –413

V

V

а b c d e f

*

50 40 2θ, deg

110

–100 –101 –102

002

V

V

V

103

*

10

V

*

V –301

210 021 –212

V

*

MoO2 MoS2

211 –220 –312 –222 –213

–200 111 –211 –202

*

60

70

Fig. 4. XRD patterns of the solid residue (coke) samples with the dispersed Mo-containing catalyst after tests on catalytic steam cracking at (a) 450°C (15 min), (b) 450°C (1 h), and (c) 425°С; (d) catalytic cracking in the absence of water at 425°C; and hydrocracking at (e) 425 and (f) 450°C.

ered structure with alternating layers, i.e., S–Mo–S. The 002 reflection characterizes the height (number) of layers. The XRD patterns show that, for the resulting molybdenum sulfide, the shapes and intensities of the 002 reflection are different. For catalytic steam cracking conducted for 1 h (Fig. 4, lines b, c), this reflection is hardly observed at all, whereas in the case of conducting this process briefly (for 15 min), it is weakly pronounced (Fig. 4, line a). The intensity of this reflection increases in the case of catalytic cracking in the absence of water (Fig. 4, line d) and hydrocracking (Fig. 4, lines e, f). This finding can apparently be attributed to the different amount and degree of dispersion of the molybdenum sulfide phase; the MoS2 phase can have different structures, namely, a different number of layers in the packing in the [001] direction. This conclusion is confirmed by the HRTEM data, which also show formation of the MoS2 phase composed of linear (needle) particles with a varying number of layers depending on conditions of heavy crude oil conversion. In general, it should be noted that there are significant differences in the size and number of molybdenum-containing particles after catalytic steam cracking and catalytic cracking in the absence of water. In the case of catalytic steam cracking, a significant portion of molybdenum is in the form of molybdenum oxide particles (an average CSR size of 340–360 Å) and molybdenum sulfide particles, whereas in the case of catalytic cracking in the absence of water, trace amounts of molybdenum oxide are formed. It can be assumed that, during the heat pretreatment of the emulsion at 210°C, ammonium heptamolybdate undergoes incomplete decomposition; it is decom-

posed to some species that dissolve in the water subsequently added to the reactor; this process, in turn, contributes to the formation of relatively large molybdenum oxide particles. In this context, to maintain the degree of dispersion of steam cracking catalyst particles, the decomposition of emulsions to water-soluble forms of the catalyst should be implemented under more severe conditions—at a higher temperature and, probably, in a hydrogen stream—before the target process. According to the revealed features of formation of catalytic dispersions for the steam cracking of HOFs, it is reasonable to develop an approach for the preliminary preparation of concentrated catalytic dispersions intended for the subsequent mixing with the main portion of the oil feedstock immediately before feeding to the reactor. Thus, the study of the features of the catalytic steam cracking of heavy crude oil from the oil fields of the Republic of Tatarstan in the presence of the nanodispersed molybdenum-containing catalyst at temperatures of 425 and 450°C has shown that this process results in formation of upgraded low-viscosity semisynthetic oil with a higher H : C ratio and a lower sulfur content than the respective parameters of semisynthetic oil produced by thermal and steam cracking. It has been found that, in the presence of the Mocontaining catalyst, water contributes to desulfurization to form sulfur-containing gaseous products and leads to an increase in the H : C ratio in the liquid products from 1.62 to 1.70. A change in the catalytic steam cracking temperature to 450°C provides a decrease in the yield of semisynthetic oil and an increase in the amount of gaseous products and coke. The hydrocracking of heavy crude oil in the presence of the Mo-containing catalyst leads to the formation of lighter products than those formed in catalytic steam cracking. It has been shown that hydrocracking at 425°C contributes to a more vigorous desulfurization, the suppression of coke formation, and an increase in the yield of fractions with Tboil < 500°C. An increase in temperature to 450°C leads to an increase in the yield of light fractions from 51 to 64 wt % and a decrease in sulfur content from 2.3 to 1.7 wt %, while the coke yield remains unchanged. According to XRD and HRTEM, under catalytic steam cracking conditions, the active component of the catalyst forms two phases, namely, molybdenum disulfide and molybdenum dioxide. It has been found that the composition and properties of the molybdenum-containing phase, in particular, MoS2 composed of linear particles with a varying number of layers, depend on the reaction medium, the process time, and the temperature of the thermal catalytic conversion of heavy crude oil. The above data suggest that, with respect to efficiency, catalytic steam cracking holds an intermediate position between thermal cracking and catalytic PETROLEUM CHEMISTRY

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hydrocracking. Thus, catalytic steam cracking is a promising process for upgrading heavy crude oil. However, insufficient knowledge of features of the process provides an array of possibilities for optimizing process parameters, in particular, the content and type of catalyst, the water to feedstock ratio, the process time, and the catalytic dispersion preparation method, in order to achieve an HOF upgrading efficiency close to that of hydroprocesses. ACKNOWLEDGMENTS This work was supported by the Russian Science Foundation, project no. 15-13-00106. REFERENCES 1. A. A. Sukhanov and Yu. E. Petrova, Neftegaz. Geol. Teor. Prakt., No. 3, 1 (2008). 2. P. M. Eletskii, O. O. Mironenko, G. A. Sosnin, O. A. Bulavchenko, O. A. Stonkus, and V. A. Yakovlev, Catal. Ind. 8, 328 (2016). 3. A. G. Okunev, E. V. Parkhomchuk, A. I. Lysikov, P. D. Parunin, V. S. Semeikina, and V. N. Parmon, Rus. Chem. Rev. 84, 981 (2015). 4. L. C. Castaneda, J. A. D. Munoz, and J. Ancheyta, Catal. Today 220–222, 248 (2014). 5. B. P. Tumanyan, N. N. Petrukhina, G. P. Kayukova, D. K. Nurgaliev, L. E. Foss, and G. V. Romanov, Rus. Chem. Rev. 84, 1145 (2015). 6. J. N. R. Olvera, G. J. Gutierrez, J. A. R. Serrano, A. M. Ovando, V. G. Febles, and L. D. B. Arceo, Catal. Commun. 43, 131 (2014). 7. N. N. Petrukhina, G. P. Kayukova, G. V. Romanov, B. P. Tumanyan, L. E. Foss, I. P. Kosachev, R. Z. Musin, A. I. Ramazanova, and A. V. Vakhin, Chem. Technol. Fuels Oils 50, 315 (2014). 8. N. N. Petrukhina, Candidate’s Dissertation in Engineering (Moscow, 2014). 9. C. Wu, G. L. Lei, C. Yao, K. Sun, P. Gai, and Y. Cao, J. Fuel Chem. Technol. 38, 684 (2010). 10. C. Kun, C. Yanling, L. Jian, Z. Xianmin, and D. Bingyang, Fuel Process. Technol. 104, 174 (2012). 11. F. Zhao, Y. Liu, Y. Wu, X. Zhao, and L. Tan, Chem. Technol. Fuels Oils 48, 273 (2012). 12. Y. H. Shokrlu and T. Babadagli, J. Petrol. Sci. Eng. 119, 210 (2014). 13. S. Desouky, A. Alsabagh, M. Betiha, A. Badawi, A. Ghanem, and S. Khalil, Int. J. Chem. Mol. Nucl. Mater. Metall. Eng. 7, 638 (2013). 14. V. A. Lyubimenko, N. N. Petrukhina, B. P. Tumanyan, and I. M. Kolesnikov, Chem. Technol. Fuels Oils 50, 292 (2012). 15. O. Muraza and A. Galadima, Fuel 157, 219 (2015). 16. A. V. Galukhin, A. A. Erokhin, Y. N. Osin, and D. K. Nurgaliev, Energy Fuels 29, 4768 (2015). 17. A. Yusufa, R. S. Al-Hajria, Y. M. Al-Waheibia, and B. Y. Jibrilb, J. Taiwan Inst. Chem. Eng. 67, 45 (2016).

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Translated by M. Timoshinina