Two-Stage Hydrotreating of Athabasca Heavy Gas ... - ACS Publications

5854

Ind. Eng. Chem. Res. 2004, 43, 5854-5861

Two-Stage Hydrotreating of Athabasca Heavy Gas Oil with Interstage Hydrogen Sulfide Removal: Effect of Process Conditions and Kinetic Analyses Christian Botchwey,† Ajay K. Dalai,*,† and John Adjaye‡ Catalysis and Chemical Reaction Engineering Laboratories, Department of Chemical Engineering, University of Saskatchewan, Saskatoon, Saskatchewan S7N 5C9, Canada, and Syncrude Edmonton Research Centre, Edmonton, Alberta T6N 1H4, Canada

Two-stage hydrodenitrogenation (HDN)-hydrodesulfurization (HDS) of heavy gas oil, derived from Athabasca bitumen, has been carried out in a trickle-bed microreactor using a commercial NiMo/Al2O3 catalyst. The operating conditions for the experiments were varied as follows: temperature range of 340-420 °C, reactor pressure of 950-1600 psig, liquid hourly space velocity range of 0.5-2.0 h-1, and hydrogen to heavy gas oil ratio of 600 mL/mL. Variation in the catalyst loading between stages I and II was also studied. Stage I products were stripped off any generated hydrogen sulfide and further hydrotreated in stage II to see the impact of hydrogen sulfide interstage removal on the hydrotreating activities. A comparison of the two-stage results to those of the single-stage results shows an enhancement in the hydrotreating activities. For instance, a 12.6 wt % increase in the conversion of nonbasic nitrogen was observed. The optimum conditions for higher gain in HDN and HDS due to hydrogen sulfide removal were found to be 380 °C, 7.6 MPa, and 1:3 (w/w) catalyst loading. A Langmuir-Hinshelwood model developed for the hydrogen sulfide inhibition predicts sufficiently the observed data of the two-stage process. 1. Introduction Conventional crude oil supply has been on a steady decline for some time now.1,2 In Canada, the progressive decline in the production of commercial light oil has been offset by oil sand production, which has doubled over the past decade. In Alberta, Canada, natural bitumen deposits comprise at least 85% of the world’s total bitumen in place.3 With such a huge resource base (1700 billion bbl of bitumen recoverable from Canada’s oil sands), the prospects are for further increases in oil sand and heavy oil production.4,5 Syncrude Canada Ltd. operates a surface mining oil sand plant in northern Alberta.6,7 The oil sand bitumen and bitumen-derived gas oil contain high levels of nitrogen and sulfur contaminants compared to conventional crude oils. The presence of these contaminants serves as a source of pollution to the environment by way of emissions from power plants, refineries, and automobiles. Besides, the presence of nitrogen causes deactivation of catalysts used in downstream processes such as fluid catalytic cracking.8 It is essential, therefore, to rid the oil of these contaminants in order to produce cleaner fuel from bitumen-derived gas oil. This is accomplished at Syncrude by hydrotreating the feedstock over Ni-Mo-based catalysts. Hydrogen sulfide (H2S), which is a byproduct of hydrotreating, is reported to be an inhibitor to the hydrotreating process.9-12 There have been conflicting reports, however, on how hydrodenitrogenation (HDN) is affected by the presence of H2S. While the above papers have reported an inhibitory effect of H2S gas on * To whom correspondence should be addressed. Tel.: (306) 966-4771. Fax: (306) 966-4777. E-mail: [email protected]. † University of Saskatchewan. ‡ Syncrude Edmonton Research Centre.

HDN, others have reported enhancement in the HDN process due to the presence of H2S.13,14 H2S competes with the organosulfur and organonitrogen compounds for the same active catalyst sites in the reaction process.15 In a study of the effect of H2S on HDN, Nagai et al.16 observed that, at 360 °C and 10.1 MPa pressure, H2S was required to increase the activity of the catalyst, but once in the fully sulfided state, further addition of H2S led to a decrease in HDN activity. H2S inhibition studies on 4-methyldibenzothiophene (4-MDBT) and 4,6-dimethyldibenzothiophene (4,6-DMDBT) at 280420 °C and 2.9 MPa over Co-Mo/Al2O3 and Ni-Mo/ Al2O3 catalysts by Ma et al.17 showed that a replacement of the reaction atmosphere, containing H2S, with fresh H2 enhanced the hydrodesulfurization (HDS) activities of the compounds. Zhang et al.18 also investigated the effect of H2S on HDS of dibenzothiophene (DBT) and 4,6-DMDBT at 240 and 260 °C using a commercial CoMo/Al2O3 catalyst. At a H2S constant pressure of 1.9 kPa, inhibition of DBT HDS was observed, but the inhibition decreased at higher temperatures. In a related study, Kabe et al.19,20 observed that H2S inhibited DBT HDS activity more than it did 4-MDBT and 4,6-DMDBT HDS. H2S inhibition on real feedstock HDS and HDN has also been reported in the literature. Ancheyta-Juarez et al.21 reported the H2S inhibition of HDS and HDN on real feedstock (85% by volume of straight-run gas oil and 15% light cycle oil) over a Co-Mo/Al2O3 catalyst. At operating conditions of 350-370 °C and 0.5 MPa, they observed that, as the feed H2S concentration increased, S and N in the product also increased. However, the inhibition effect was less at high temperatures as with model compounds.18 In a study of the H2S effect on HDN activity of Athabasca bitumenderived heavy gas oil, Bej et al.22 observed that increasing the concentration of H2S to levels higher than those

10.1021/ie030857f CCC: $27.50 © 2004 American Chemical Society Published on Web 07/16/2004

Ind. Eng. Chem. Res., Vol. 43, No. 18, 2004 5855 Table 1. Properties of Bitumen-Derived Gas Oil from Athabasca properties boiling range (°C) density (g/cm3) sulfur (wt %)

properties 210-600 0.99 4.0

total nitrogen (wt %) BN (wt %) NBN (wt %)

0.33 0.11 0.22

present during a normal HDS process in a reactor resulted in a decrease in conversion of both basic (BN) and nonbasic nitrogen (NBN) compounds. It was also observed that NBN conversion was more hindered than that of BN. These observations were contrary to earlier reports regarding the H2S effect on HDN.13,14 Hiroshi et al.23 have also studied the effect of H2S on straightrun light gas oil using a fixed-bed reactor at 340-360 °C and 3-5 MPa. They observed that H2S inhibition increased with increasing H2 pressure and decreased with increasing hydrogen/oil ratio. Although H2S inhibition on HDN and HDS has been widely studied, reports on the effects of process conditions and kinetic analyses on H2S inhibition of real feedstock HDN and HDS activities are scarce in the literature. Kinetic studies carried out have mainly been on model sulfur compounds.18,20 The complexity of the simultaneous reaction of the individual compounds in real feedstock makes their kinetics different from those for model compounds. The development of H2S inhibition kinetics of real feedstock would be very beneficial to the petroleum industry considering the role kinetics play in catalyst development, reactor design, and process operations. This paper will discuss the effects of process conditions, and the kinetic analyses of H2S inhibition of HDN and HDS activities using Athabasca bitumen-derived heavy gas oil and commercial Ni-Mo/ γ-Al2O3 catalyst. 2. Experimental Section The apparatus for the experimental work consisted of a 304 stainless steel trickle-bed microreactor and furnace system (Vinci Technologies SA, Nanterre, France) with an inner diameter of 10 mm and a total length of 285 mm, an Eldex metering pump, a mass flow controller for gas flow, and a temperature controller to control the furnace temperature. A schematic diagram of the experimental setup is given elsewhere.24 The feed used was bitumen-derived heavy gas oil from Athabasca, the properties of which are shown in Table 1. The catalyst was a trilobed extrudate commercial Ni-Mo/γ-Al2O3 with an average diameter of 1.5 mm. Five grams of the catalyst was diluted with 90-mesh silicon carbide particles to form a total bed length of 12 cm. The catalyst bed was sandwiched by two zones of various sizes of silicon carbide particles (Ritchey Supply Ltd.) and glass beads (Fisher Scientific) to control the hydrodynamics of the system (Figure 1). Earlier studies have shown that trickle flow is obtained in the catalyst bed with such loadings.25 The reactions were performed in two different modes to help investigate the H2S inhibition on HDN and HDS: a single-stage mode and a two-stage mode. The single-stage mode involved a once-through experimental run with no H2S removal. On the other hand, the twostage mode comprised two stages, stage I and stage II. Products from stage I were stripped of H2S and then fed to stage II. The same amount of catalyst (5 g), hydrogen-to-oil ratio (600 mL/mL), and reaction time (1 h) were used in both the single- and two-stage modes.

Figure 1. Schematic diagram of a single-stage mode catalyst loading in the microreactor.

Results in the two-stage mode were compared to those of the corresponding single-stage mode to see the effect of interstage H2S removal on HDS and HDN. Experiments involving different catalyst loadings, temperatures, and pressures were performed. In the two-stage mode, 5 g of catalyst was split in the ratio 1:3, 1:1, and 3:1 between stages I and II (i.e., stage I catalyst wt/ stage II catalyst wt) as schematically shown in Figure 2. The same oil flow rate (6.4 mL/h) was maintained for both modes of operation so that the total reaction time of 1 h (liquid hourly space velocity, LHSV, of 1 h-1) will be the same. The experiments were performed at 360, 380, and 400 °C and at four pressures of 6.5, 7.6, 8.8, and 9.6 MPa. H2S was removed from the stage I products by bubbling nitrogen through for 2 h before the products were further hydrotreated in stage II. It should be noted that, prior to the experimental runs, the catalyst was sulfided with a butanethiol solution in a hydrogen flow and stabilized with heavy gas oil for 5 days at 375 °C, 8.8 MPa, LHSV of 1 h-1, and a hydrogento-oil ratio of 600 mL/mL. Only one reactor was used in the experimental runs. All stage I runs were performed together, after which the stage II runs were also performed in the same reactor after loading the required amount of fresh catalyst. The products collected after both stages I and II were analyzed for their sulfur, total nitrogen, BN, and NBN content. The sulfur content was analyzed by a combustion/fluorescence technique, while the total nitrogen content was measured by a combustion/chemiluminence technique. The BN content was obtained by titration of the sample against a potassium hydroxide solution and NBN by the difference between the total nitrogen and BN. The essence of the H2S removal was to see how the presence of H2S affects the HDS and HDN results in a single-stage process. On the other hand, the different catalyst loadings were to investigate the best position along the catalyst bed to remove H2S from the reaction system. 3. Results and Discussion 3.1. Effect of H2S on HDS and HDN. In this work, the effect of H2S on HDS and HDN was studied using

5856 Ind. Eng. Chem. Res., Vol. 43, No. 18, 2004

Figure 2. Schematic diagram of a two-stage mode catalyst loading.

a two-stage process at different catalyst loadings in stages I and II and at different operating temperatures and hydrogen pressures. The results of the two-stage process were then compared to a corresponding singlestage process with the same operating conditions but no H2S removal. Results of the single-stage HDS and HDN have been discussed in an earlier publication.24 The experiments were repeated at various temperatures to test the reproducibility of the results. Error analyses published earlier24 gave a highest error margin of (0.3 wt % for HDS and an average maximum error of (1.6 wt % for the HDN process. The marginal error observed is due to the nature of the experimental design. For each run, three samples were taken at 24-h intervals. The samples were then analyzed and results averaged to give one data point. The parameter describing the impact of H2S removal on HDS and HDN, gain, was defined as follows:

or HDN conversion gain ) HDS in the two-stage process HDS or HDN conversion in the single-stage process

[

]

[

]

Gain is a measure of the H2S inhibition; hence, a positive gain means that the interstage removal of H2S enhances HDS and HDN activities and vice versa. 3.1.1. Inhibition of H2S at Varying Operating Temperatures. The effects of H2S on HDS and HDN were studied at the temperatures 360, 380, and 400 °C using a catalyst loading of 1:1 (w/w; stage I catalyst weight/stage II catalyst weight) and a pressure of 8.8 MPa. A comparison of the single- and two-stage HDS and HDN activities is shown in Figure 3. As the temperature increases, gain in HDS decreases, which can be attributed to a decrease in the extent of H2S adsorption on the catalyst surface with increasing temperature. This is in agreement with previous reports10,23 in which inhibition by H2S decreases at higher temperatures. The total nitrogen HDN gain was generally higher than that of HDS, implying that the total nitrogen HDN was inhibited more than HDS. In the case of BN and NBN HDN, the plots show that the activity for NBN can be significantly enhanced if H2S is removed from the reaction environment. At 380 °C, for instance, NBN HDN can be enhance by 8 wt %

Figure 3. Effect of temperature and interstage H2S removal in a two-stage hydrotreating unit relative to a single-stage unit [pressure, 8.8 MPa; LHSV, 1 h-1; hydrogen/oil, 600 mL/mL; catalyst loading, 1:1 (w/w)].

if H2S is removed midway along the catalyst bed. In the case of BN, the gain is not high, indicating relatively the same H2S inhibition in both the single- and twostage processes. It can also be observed that the maximum HDN activity occurs at 380 °C. 3.1.2. Inhibition of H2S at Varying Catalyst Loadings. For H2S interstage removal, it is important to know the point along the catalyst bed at which H2S can be removed to give the best HDS and HDN results. To help solve this problem, experiments were carried out with three different catalyst loadings in the twostage process, each with interstage H2S removal, and the results were compared to the corresponding singlestage process with no H2S removal. The catalyst loadings between stages I and II were in the ratio 1:3 and 3:1 (w/w) and compared to the 1:1 (w/w) catalyst loading. Each loading was studied at three temperatures (360, 380, and 400 °C), and the operating pressure was 8.8 MPa. The results are illustrated in Figure 4 and Table 2. A gain in conversion in the two-stage process is observed because HDS and HDN activities are inhibited by the presence of H2S in the corresponding single-stage process. H2S is competitively adsorbed on the active catalyst sites and hence hinders the conversion of the sulfur and nitrogen compounds. In a similar study, Kabe et al.19 reported that the adsorption constant of H2S was

Ind. Eng. Chem. Res., Vol. 43, No. 18, 2004 5857

Figure 4. Effect of catalyst loading and interstage H2S removal in a two-stage hydrotreating unit relative to a single-stage unit (temperature, 380 °C; pressure, 8.8 MPa; LHSV, 1 h-1; hydrogen/ oil, 600 mL/mL).

Figure 5. Effect of pressure and interstage H2S removal in a twostage hydrotreating unit relative to a single-stage unit [temperature, 380 °C; LHSV, 1 h-1; hydrogen/oil, 600 mL/mL; catalyst loading, 1:3 (w/w)].

Table 2. Effect of Temperature, Pressure, and Interstage H2S Removal on HDS and HDN in a Two-Stage Unit at 1:3 (w/w) Catalyst Loading Relative to a Single-Stage Unit (LHSV, 1 h-1; Hydrogen/Oil, 600 mL/mL)

Table 3. Effect of Temperature, Pressure and Interstage H2S Removal on HDS and HDN in a Two-Stage Unit at 3:1 (w/w) Catalyst Loading Relative to a Single-Stage Unit (LHSV, 1 h-1; Hydrogen/Oil, 600 mL/mL) gain (wt %)

gain (wt %) pressure (MPa)

sulfur

total nitrogen

BN

NBN

pressure (MPa)

sulfur

total nitrogen

BN

NBN

1.8 2.3 1.9 0.9

3.4 4.7 6.6 3.2

6.7 7.6 8.8 9.6

Hydrotreating at 360 °C 4.4 4.3 6.3 3.4 3.5 3.9 2.8 1.5

-0.6 -1.1 -1.5 -0.3

7.0 5.9 6.9 2.5

6.7 7.6 8.8 9.6


6.7 7.6 8.8 9.6


2.9 2.4 1.2 0.8

5.4 7.6 2.4 2.4

6.7 7.6 9.6

Hydrotreating at 380 °C 2.4 2.4 2.6 4.6 1.6 2.9

0.8 2.4 1.6

3.4 5.8 3.7

6.7 7.6 8.8 9.6


0.2 0.9 0.8 0.3

4.1 0.7 1.2 0.8

greater than those of DBT compounds, which probably accounts for the observed inhibition. Generally, at all catalyst loadings, the removal of H2S in the two-stage process results in a higher gain in the HDN activity of NBN compounds compared to BN HDN. This may be due to the strongly basic nature of BN compounds.26 Their adsorption constant may be stronger than that of H2S on a Ni-Mo/Al2O3 catalyst and, hence, not significantly inhibited by H2S. Similarly, the total nitrogen HDN gain was generally higher than the HDS gain. The catalyst loading that gives the highest gain in conversion, especially in the HDN processes, appears to be 1:3 (w/w). This observation could be due to the fact that the first trace of H2S that is formed up the catalyst bed occupies the active catalyst sites. Hence, an early removal of the generated H2S from the reaction environment (up the catalyst bed) leads to greater reduction in inhibition and a higher gain in conversion in the two-stage process. 3.1.3. Inhibition of H2S at Varying Pressures. Studies on the H2S inhibition at different catalyst loadings indicated that 1:3 (w/w) generally gives the best results. Hence, further studies on the 1:3 (w/w) catalyst loading were done at four different operating pressures (6.5, 7.6, 8.8, and 9.6 MPa) to find the impact of pressure on H2S inhibition of HDS and HDN as well as to determine the optimum operating pressure. Three operating temperatures (360, 380, and 400 °C) were used for each pressure. Figure 5 indicates high inhibition in the single-stage processes. The gain did not follow any specific pattern, but it was obvious that a pressure of 7.6 MPa gave the optimum HDN gain. A

NBN HDN gain of 12.6 wt % was observed at 380 °C and 7.6 MPa. As the pressure increased, the gain decreased (Table 2), although this was not so clear in Figure 5. At high hydrogen pressures, the partial pressure of H2S formed in the reaction system reduces. The inhibitory effect of H2S, therefore, decreases when the operating pressure increases. At most pressures, the gain in the total nitrogen HDN was higher than that in HDS. This may be because HDN is more inhibited by H2S in hydrotreating of Athabasca heavy gas oil than HDS. It can also be inferred that H2S did not inhibit HDN of BN as it did NBN. Results of experiments at the 3:1 (w/w) catalyst loading with varying pressures are also shown in Table 3. A comparison of the results in Tables 2 and 3 shows generally higher gains for the 1:3 (w/w) catalyst loading relative to the 3:1 catalyst loading at all pressures. This confirms the finding that an early removal of H2S up the bed gives a better gain. The results show that a higher gain in HDS and HDN activities can be obtained at lower operating pressures. 3.2. Kinetic Analysis. The two-stage process was designed to study the effect of H2S gas on the hydrotreating process. All H2S produced in stage I was removed and the product fed to stage II for further hydrotreating. To model the H2S inhibition at each stage of the process, the Langmuir-Hinshelwood model was applied. The kinetic analysis was considered in two parts: stage I kinetics and stage II kinetics. Total inhibition in the system was associated with self-


inhibition (from the reactant sulfur or nitrogen compound), inhibition due to hydrogen and that due to H2S. This consideration led to a general model of the form

-riθ )

kiθKiKH2PH2Ciθ 1 + KiCiθ + KH2PH2 + KH2SPH2S

)-

dciθ dt

KS - KH2Sb

χS )

1 + KH2PH2 + KH2SbCS0

[

exp (1 + KH2PH2 + KH2SbCS0) ln(CS0) -

(1)

kS1KSKH2PH2 LHSV

where riθ is the rate of reaction of species i in the θth stage (stage I or II), kiθ is the apparent rate constant of species i in the θth stage, and Ki, KH2, and KH2S are the adsorption constants of species i, hydrogen, and H2S, respectively. i is either an organosulfur or organonitrogen compound. PH2 and PH2S are the partial pressures of hydrogen and H2S, respectively, and Ciθ is the concentration of species i in the θth stage. Assuming that H2S is an ideal gas, the partial pressure of H2S can be written in the form

n PH2S ) RT ) b(CS0 - CSp) ) bCS V

kS1KSKH2PH2CS1 1 + KSCS1 + KH2PH2 + KH2SPH2S

)-

1 + KH2PH2 + KH2SbCS0 (4b)

The four unknown kinetic parameters were evaluated simultaneously by a nonlinear least-squares method. Similarly, the rate of HDN in stage I can be written in the form

-rN1 ) kN1KNKH2PH2CN1 dCN1 ) dt 1 + KNCN1 + KH PH + KH Sb(CS0 - CS1)

-

2

2

2

(2)

where b is a constant, CS0 and CSp are the feed and product mass concentrations, respectively, CS is the weight percent of sulfur compound converted, and n is the number of moles. 3.2.1. Stage I Kinetic Analyses. The HDS rate equation in stage I can be written in the form

-rS1 )

]

+ (KS - KH2Sb)CS0 /

dcS1 (3) dt

where rS1 is the HDS rate in stage I, kS1 and CS1 are the apparent rate constant and concentration of sulfur in stage I, KS is the sulfur adsorption constant, and KH2, KH2S, PH2, and PH2S are as defined previously. With known product concentrations, it was essential to integrate eq 3 to obtain the working equation for parameter estimation. Because the feed sulfur is the only source for H2S production, PH2S in eq 3 can be replaced, according to eq 2, by PH2S ) b(CS0 - CS1). Substituting for PH2S and integrating (applying Maple V software, a trademark of Waterloo Maple Inc.) give

(5) -rN1 is the HDN rate in stage I, kN1 and CN1 are the apparent rate constant and concentration of sulfur in stage I, and KN, KH2, KH2S, PH2, and PH2S are the same as those defined previously. Applying Maple V software for integration yielded the solution equation

CN1 )

{

exp [1 + KH2PH2 + KH2Sb(CS0 - CS1)][ln(CN0) W(χN)] -

kN1PH2

}

+ KNCN0 / LHSV 1 + KH2PH2 + KH2Sb(CS0 - CS1) (6)

where χN is given by

χN )

KN 1 + KH2PH2 + KH2Sb(CS0 - CS1)

{

exp [1 + KH2PH2 + KH2Sb(CS0 - CS1)] ln(CN0) kN1PH2 LHSV

}

+ KNCN0 /1 + KH2PH2 + KH2Sb(CS0 - CS1) (6a)

CS1 )

[

exp {1 + KH2PH2 + KH2SbCS0}{ln(CS0) - W(χS)} kS1KSKH2PH2 LHSV

]

+ (KS - KH2Sb)CS0 / 1 + KH2PH2 + KH2SbCS0 (4)

where W(χi) is the Lambert W function given by the series expansion

(-1)j-1nn-2 j χi ) W(χi) ) j)1 (j - 1)! 3 8 125 5 54 6 χi - χi + ... (4a) χi - χi2 + χi3 - χi4 + 2 3 25 5 ∞

∑

and

With KH2 and KH2S already known from the stage I HDS analyses, only two parameters were evaluated by the nonlinear least-squares analyses, i.e., KN and kN1. 3.2.2. Stage II Kinetic Analyses. Any H2S produced in stage I is removed before the stage I product was fed to stage II. This means H2S available for inhibition in stage II will be a measure of CS1 - CS2, where CS1 and CS2 are the product concentrations of stages I and II, respectively. The HDS reaction in stage II can also be represented as

-rS2 ) kS2KSKH2PH2CS2 1 + KSCS2 + KH2PH2 + KH2Sb(CS1 - CS2)

)-

dcS2 (7) dt

-rS2 is the HDS rate in stage II, kS2 and CS2 are the apparent rate constant and concentration of sulfur in

Ind. Eng. Chem. Res., Vol. 43, No. 18, 2004 5859 Table 4. Apparent Kinetic Parameters for Two-Stage HDS and HDN Processes [Pressure, 8.8 MPa; LHSV, 1 h-1; Hydrogen/Oil, 600 mL/mL; Catalyst Loading, 1:1 (w/w)] parameter

ln(kI)a

ln(kII)a

ln(KHT)b

ln(KH2)b

ln(KH2S)b

E [kJ/mol] ln(k0 or K0) r2 STDEV

114.2 22.7 0.997 stage I

100.8 18.9 0.979 0.7

(-)8 -4.7 0.998 stage II

7 3.2 0.998 1.0


HDN of Total Nitrogen 93.5 115.5 (-)5.7 12.7 15.7 2.4 0.997 0.980 0.994 stage I 3.0

(-)8 -4.7 0.998 stage II

7 3.2 0.998 1.6


193.5 12.7 0.997 stage I

HDN of BN 115.5 (-)2.4 15.7 2.4 0.980 0.994 3.0

(-)8 -4.7 0.998 stage II

7 3.2 0.998 1.6


93.5 12.5 1.000 stage I

HDN of NBN 154.3 (-)7.4 22.5 2.4 0.999 0.994 2.9

(-)8 -4.7 0.998 stage II

7 3.2 0.998 2.4

HDS 52.2 -8.7 0.999

a ln k ) ln(k ) - E/RT. θ is either stage I or II (i.e., 1 or 2). b ln θ 0 Ki ) ln(K0) + E/RT. i is either S, N, H2, or H2S.

stage II, and KS, KH2, KH2S, PH2, and PH2S are the same as those in stage I above. Integrating eq 7 (using Maple V software) yields a relation similar to that in eq 4. When kS2 is substituted for kS1 and the right concentrations and known parameters are used from stage I, only one parameter, kS2, is left to be evaluated by the nonlinear least-squares technique. The rate of HDN in stage II can also be written in the form

Figure 6. HDN and HDS parity plots for data used in developing model parameters [temperature, 360-400 °C; pressure, 8.8 MPa; hydrogen/oil, 600 mL/mL; catalyst loading, 1:1 and 3:1 (w/w)].

-rN2 ) -

kN2KNKH2PH2CN2 dCN2 ) dt 1 + KNCN2 + KH2PH2 + KH2Sb(CS1 - CS2) (8)

-rN2 is the HDN rate in stage II, kN2 and CN2 are the apparent rate constant and concentration of sulfur in stage II, and KN, KH2, KH2S, PH2, and PH2S are the same as those defined in stage I above. Integrating eq 8 results in a relation similar to eq 6. By correct substitution of known parameters and concentrations, kN2 can be evaluated by the nonlinear least-squares technique. 3.2.3. Parameter Estimation. The nonlinear leastsquares technique involved minimization of error, i.e., the sum of squares of the difference between the experimental (observed) product concentration and the corresponding calculated concentration.27 The set of parameter values that minimizes the error is chosen to be the correct set of parameters for the model from which the activation energies, heat of adsorptions, and preexponential factors are evaluated. The initial parameter estimates were selected from the literature.28 The kinetic parameters for both stages I and II are presented in Table 4. The high regression coefficients obtained indicate the reliability of the data. Figures 6 and 7 illustrate the correlation between the experimental and model-predicted values for the HDS and HDN processes. While Figure 6 predicts the data used in the model development, Figure 7 predicts a new set of data

Figure 7. HDN and HDS parity plots for new experimental data and model prediction [temperature, 360-400 °C; pressure, 8.8 MPa; hydrogen/oil, 600 mL/mL; catalyst loading, 1:3, 1:1, and 3:1 (w/w)].

not included in the model development. Data used in the models were the 3:1 catalyst loading process for BN HDN and the 1:1 catalyst loading for the others. There is a good agreement between the model prediction and the experimentally observed data at different operating temperatures and catalyst loadings with a maximum


standard deviation of 3 wt %. The standard deviations for each model are also given in Table 4. An effort was made to obtain a general model with common parameters for both stages I and II using the data available. It was, however, observed that the models obtained could adequately predict data for one particular stage but poorly predict the other. This was not unexpected considering the nature of the experimental design and the feed used. The reaction rate and adsorption constants are functions of the catalyst type, temperature, and feedstock.29 Real feedstock is composed of different complex compounds containing sulfur, nitrogen, etc., each with its own reactivity and hydroprocessing kinetics.5,17 In hydrotreating process, the easy-to-react compounds react first, giving off the bulk of H2S such that the difficult-to-react compounds operate in a H2S regime.9 This means that in our work the feedstock to the two stages will be different because the easy-to-react compounds would react in stage I, leaving the difficult-to-react compounds to react in stage II. This may be the reason common parameters could not be obtained for the two stages. To reduce the number of parameters in the models, the adsorption constant was made the same for both stages I and II while the reaction rate constant varied. As described earlier, the parity plots (see Figure 6) for the data used to estimate the model parameters (Table 4) have been separated from those of the prediction of other data not used in the model development (Figure 7). The results in Figure 7 show that the parameters estimated adequately predict the new experimental data. 4. Conclusions 1. H2S inhibits both HDS and HDN activities of Athabasca bitumen-derived heavy gas oil. The removal of H2S from the reaction environment enhances the overall activities of HDS and HDN of total nitrogen. 2. H2S removal enhances HDN of NBN but does not have much effect on HDN of BN compounds. 3. The optimum conditions for higher gain in HDN and HDS are 380 °C, 7.6 MPa, and 1:3 (w/w) catalyst loading. 4. The gain in HDN and HDS activities decreases with increases in temperature and pressure. 5. The kinetic models developed for the two-stage processes using the Langmuir-Hinshelwood approach adequately predict the experimental data. Acknowledgment Financial support from the Natural Science and Engineering Research Council of Canada (NSERC) in terms of Collaboration Research and Development (CRD) grant and from Syncrude Canada is greatly acknowledged. Nomenclature b ) constant relating hydrogen sulfide partial pressure to moles of hydrogen sulfide [MPa (wt %)-1] Ciθ ) concentration of species i in the θth stage (w/w) CS ) concentration of sulfur species (wt %) CS0 ) feed concentration of sulfur species (wt %) CSp ) product concentration of sulfur species (wt %) E ) activation energy (kJ/mol) i ) sulfur, total, basic, or nonbasic nitrogen compound k ) rate of reaction k0, K0 ) preexponential factor

kθ ) rate constant in the θth stage kiθ ) rate constant of species i in the θth stage K ) adsorption constant KH2 ) adsorption constant of hydrogen gas (MPa-1) KH2S ) adsorption constant of hydrogen sulfide gas (MPa-1) KHT ) adsorption constant of a sulfur or nitrogen compound (MPa-1) Ki ) adsorption constant of species i LHSV ) liquid hourly space velocity (h-1) n ) number of moles PH2 ) pressure of hydrogen gas (MPa) PH2S ) pressure of hydrogen sulfide gas (MPa) r ) regression coefficient riθ ) rate of reaction of species i in the θth stage (stage I or II) (wt % h-1) R ) gas constant (J mol-1 K-1) STDEV ) standard deviation t ) time (h) T ) temperature (°C) V ) volume of the catalyst (mL) W ) Lambert W function Greek Letters θ ) stage I or II χi ) argument for the Lambert W function for species i

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Received for review December 1, 2003 Revised manuscript received May 20, 2004 Accepted May 20, 2004 IE030857F

Two-Stage Hydrotreating of Athabasca Heavy Gas ... - ACS Publications

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