Ind. Eng. Chem. Res. 2009, 48, 10253–10261
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Industrial Investigation on the Origin of Sulfur in Fluid Catalytic Cracking Gasoline Dicho S. Stratiev,*,† Ivelina Shishkova,† Todor Tzingov,† and Per Zeuthen‡ Research and DeVelopment Department, Lukoil Neftochim Bourgas, 8104 Bourgas, Bulgaria, and Catalyst DiVision, Haldor Topsoe
Industrial experiments on the addition of H2S to the fluid catalytic cracking (FCC) feed (hydrotreated vacuum gas oil) were carried out in the commercial FCC unit at Lukoil Neftochim, Bulgaria. It was found that during cracking of pure hydrotreated vacuum gas oil to which was added about 550 ppm H2S that the FCC gasoline contained about 12 ppm more sulfur than the nonspiked feed. Both gasolines obtained from the pure feed and the H2S-spiked feed contained the same type of sulfur compounds: mercaptans, thiophenes, and benzothiophenes. In the case of the H2S-spiked feed, the additional FCC gasoline sulfur formed was about 1.2% of the sulfur in the H2S added to the feed. The FCC gasoline sulfur formed from the pure FCC feed, on the other hand, was about 2.5% of the sulfur in the feed. The higher percent of sulfur conversion of the pure FCC feed relative to the conversion of the H2S suggests that both reaction of H2S with olefins or diolefins (from the catalytic cracking of the hydrocarbons of the feed) and transformation of heavy sulfur compounds contained in the feed may be responsible for the entire FCC gasoline sulfur compounds formation. Introduction Tighter gasoline quality specifications around the world are forcing refiners to produce gasoline with extremely low sulfur. The European Union specified the upper limit for sulfur in gasoline as 10 ppm, and the USA mandated 30 ppm. Fluid catalytic cracking (FCC) gasoline is responsible for more than 90% of the sulfur in the finished gasoline pool. To meet the challenge of reducing gasoline sulfur, refiners are, therefore, focusing their attention on the FCC unit. In recent years, a large number of articles have been published that discuss sulfur distribution in FCC effluents.1-11 Various mechanisms have been proposed for the production of sulfur species in FCC gasoline.5,6 It is known that a larger proportion on the feed sulfur from unhydrotreated feed ends up in the FCC gasoline in contrast to hydrotreated feed (Table 1). Unhydrotreated feeds contain mercaptans, sulfides, and thiophenes which under FCC conditions can be cracked to lower molecular weight mercaptans, sulfides, and thiophenes boiling in the gasoline range.11 In the case of hydrotreated FCC feeds, hydrotreating usually removes the “easy” sulfur species such as mercaptans, sulfides, and thiophenes leaving only the “difficult” dibenzothiophenes with substituents in the 4- and 6-positions.12 Therefore, the presence of mercaptans in the FCC gasoline obtained by cracking hydrotreated feed cannot be explained by the mechanism of feed mercaptans cracking. Leflaive et al.6 and Zeuthen12 proposed a mechanism of FCC gasoline sulfur species formation through the reaction of large amounts of H2S with olefins or diolefins produced as a consequence of the hydrocarbon cracking reactions.6,12 Such a mechanism could explain the presence of mercaptans, sulfides and thiophenes in the FCC gasoline obtained by cracking hydrotreated feed. The FCC unit at Lukoil Neftochim Bulgaria (LNB) currently processes hydrotreated heavy vacuum gas oil (HTHVGO). For a period of time, this unit processed a blend of stable (stripped) * To whom correspondence should be addressed. E-mail:
[email protected]. † Lukoil Neftochim Bourgas. ‡ Haldor Topsoe.
HTHVGO and unstable (unstripped) HTHVGO. About 90% of the sulfur in the unstable HTHVGO is in the form of H2S.15 The pure stable HTHVGO sulfur content depends on the FCC feed hydrotreater severity and varies between 0.017 and 0.08% while in the mixed LNB FCC unit feed (stable + unstable HTHVGO), the total sulfur content varies between 0.0757 and 0.1126%sof which the H2S is about 0.055%. The presence of H2S in the feed allows us to establish its role in the formation of gasoline range sulfur species in the FCC process and is the aim of this work. Experimental Section This study was carried out on the LNB FCC unit which consists of feed hydrotreater section, FCC reactor-regenerator and main fractionator section, vapor recovery section, and a Merox unit (Figures 1 and 2). The LNB FCC reactor is equipped with the modern UOP VSS riser termination device and the UOP Optimix feed injection system. The operating conditions at which the experiments were carried out in the FCC reactor-regenerator section were as follows: throughput ) 214 t/h; riser outlet temperature ) 538 °C; combined feed temperature ) 332 °C; reactor pressure ) 1.02 kg/cm2; regenerator dense bed temperature ) 660 °C; regenerator dilute phase temperature ) 671 °C; air ) 119-123 kN m3/h; catalyst-to-oil ratio ) 8.8 wt/wt; residence time ) 2.5 s. The FCC catalyst employed during the study was a partially exchanged RE-USY zeolite containing octane catalyst. Its physical and chemical properties in equilibrium state are summarized in Table 2. The FCC feed hydrotreater section employed a Co-Mo hydrotreating catalyst, and the operating conditions at which the LNB FCC feed hydrotreater was investigated are summarized in Table 3. Experiments in the FCC reactor-regenerator section were performed with an FCC feed that consisted of 100% stable HTHVGO, that did not contain H2S, and an FCC feed that consisted of about 70% stable HTHVGO and 30% unstable HTHVGO. By mixing the stable HTHVGO with the unstable HTHVGO, H2S was introduced into the FCC feed. Properties of the stable HTHVGO and the unstable HTHVGO are summarized in Table 4. In order to avoid the influence of
10.1021/ie900985g CCC: $40.75 2009 American Chemical Society Published on Web 10/28/2009
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Table 1. Dependence between FCC Feed Sulfur and the FCC Gasoline Sulfur for Unhydrotreated and Hydrotreated FCC Feeds unhydrotreated FCC feeds a
FCC feed sulfur, % FCC gasoline sulfur, % Ratio FCC feed sulfur/FCC gasoline sulfur a
b
1.2 0.1299 9.2
2.26 0.29 7.8
hydrotreated FCC feeds c
1.65 0.1650 10.0
a
0.06 0.0020 30.0
0.1947b 0.0069 28.2
0.0835b 0.0029 28.8
0.32c 0.0102 31.4
Reference 13. b Reference 12. c Reference 14.
Table 2. Physical and Chemical Properties of the Equilibrium Catalyst Used in the Study chemical composition Al2O3, % Na2O, % RE2O3, % Fe, % V, ppm Ni, ppm MAT conversion, %
D- 3710. The specific gravity of the VGO and the gasoline was measured in accordance with ASTM D-1298.
physical properties 41.4 0.14 1.58 0.56 208 35 73
APS, µm ABD, g/mL SA, g/m2 UCS, 10-9 m
76 0.92 140 2.427
cut point on the FCC gasoline sulfur, only FCC gasoline samples with an ASTM D-86 distillation end boiling point of 206 ( 4 °C (T90 ) 176 ( 4 °C) were considered in the study. Analysis of total sulfur in the FCC hydrotreater feed (Ural HVGO) and the FCC reactor-regenerator section feed (stable HTHVGO) was performed in accordance with ASTM D-2622. The total sulfur in the FCC gasoline was measured according to ASTM D-7212. The FCC feed and gasoline sulfur type was analyzed by the atomic emission detector- sulfur distribution method (AED-S D.M.). The level of aromatics and aromatics distribution in the HVGO, the HTHVGO, and the FCC gasoline has been determined by the IP 548 method. The distillation of FCC gasoline was carried out in accordance with the ASTM
Results and Discussion The data in Table 3 indicate that an increase of the FCC feed hydrotreater severity from 347 to 374 °C resulted in an increase of conversion from 6.3 to 13.7 and a decrease of stable hydrogenate (stable HTHVGO) sulfur from 0.0698 to 0.0175%. It also resulted in an increase of denitrogenation degree and a reduction of polynuclear to mononuclear aromatic saturation (Table 4). Analysis of sulfur compounds distribution in the FCC hydrotreater feed and in the HTHVGO having total sulfur of 0.0698% is presented in Figures 3 and 4. These data indicate that the Ural HVGO contains benzothiophenes, dibenzothiophene, and substituted dibenzothiophenes. After 95% hydrodesulfurization, the benzothiophenes were completely removed and the most dominant compounds in the hydrotreated HTHVGO were 4,6-dimethyldibenzothiophene and other refractive sterically hindered dibenzothiophenes. There were several compounds in a rather low concentration, which were all heavier than the dibenzothiophenes hidden in the hump of the spectra. Some of the compounds hidden in the hump may be heavily substituted dibenzothiophenes, substituted naphthobenzothiophenes, or other triaromatic sulfur compounds.
Figure 1. Diagram of hydrotreating, FCC reactor-regenerator, and fractionation sections in the Lukoil Neftochim Bourgas FCC unit.
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Figure 2. Diagram of vapor recovery section and Merox unit in the Lukoil Neftochim Bourgas FCC unit.
Figure 3. GC sulfur type analysis of the LNB FCC hydrotreater feed (HVGO, total sulfur ) 1.48%).
Figure 4. GC sulfur type analysis of the FCC reactor-regenerator section feed (HTHVGO, total sulfur ) 0.0698%).
Data of the yield distribution, product sulfur content, and properties of the gasoline obtained during cracking of the HTHVGO mixed with H2S and the pure HTHVGO are presented in Table 5. It can be seen from these data that the H2S content in the FCC feeds spiked with H2S varied between 455 and 643 ppm and the total FCC feed sulfur varied between 757 and 1126 ppm. The presence of H2S in the FCC feed resulted in a much higher content of sulfur in dry gas that was in the form of H2S for the feed spiked with H2S. Unlike sulfur in the dry gas, the sulfur in all remaining FCC products decreased with a reduction of organic sulfur in the FCC feed during cracking of the feed spiked with H2S. Sulfur in all FCC products diminished with lowering of feed sulfur during cracking of the pure feed. The data in Table 5 indicate that gasoline and cycle oils (light and heavy cycle oils) obtained by cracking of H2S-spiked feed contain more sulfur. If a comparison is made between sulfur in gasoline and LCO obtained by cracking of the pure FCC feed whose organic sulfur is 304 ppm (column eight of Table 5) and that spiked with 558 ppm H2S feed whose organic sulfur is 232 ppm (column four of Table 5), one can see that gasoline sulfur from the pure FCC feed is 14 versus 21 ppm from the H2S-spiked feed; the LCO sulfur from the pure feed is 184 versus 453 ppm from the H2S-spiked feed. Keeping in mind that separation between LCO, HCO, and slurry in the commercial FCC main fractionator is not precisely correct,
comparison between sulfur in FCC gas oils can be made if the yields of gas oil fractions are combined and total sulfur of the combined gas oil fraction (210-530 °C) is determined. It is evident that sulfur in the combined gas oil fraction for the case discussed above is again higher for the H2S-spiked feed (1187 versus 1036 ppm) which suggests that H2S may contribute to formation not only of sulfur species boiling in the gasoline range but also to such boiling in the gas oil range. Besides the data set for the cracking of pure HTHVGO given in Table 5, additional data for sulfur in the gasoline are presented in Figure 5. It shows a dependence of the FCC gasoline sulfur (T90 ) 176 ( 4 °C) on the stable HTHVGO sulfur for the pure FCC feed and for the one spiked with about 550 ppm H2S. It is evident from these data that the FCC gasoline sulfur correlates with the stable HTHVGO sulfur and that H2S leads to a step increase in FCC gasoline sulfur. If the plots of feed sulfur versus gasoline sulfur in Figure 5 are extrapolated to zero sulfur in the HTHVGO, logically zero sulfur in the FCC gasoline would be obtained for the pure FCC feed, whereas for the feed spiked with H2S, the FCC gasoline contains 12 ppm sulfur. These data suggest that a part of the H2S added to the FCC feed reacted with the FCC (olefinic) products and formed gasoline range sulfur species. In order to determine the nature of the gasoline range sulfur compounds formed from the H2S, a GC analysis was performed
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Figure 5. Dependence of the FCC gasoline sulfur on the stable HTHVGO sulfur determined during cracking of pure HTHVGO and HTHVGO contaminated with about 550 ppm H2S. Table 3. Operating Conditions and Yield Distribution in the LNB FCC Feed Hydrotreater FCC feed hydrotreater LHSV, h-1 first hydrotreating reactor inlet temperature, °C second hydrotreating reactor inlet temperature, °C second hydrotreating reactor outlet temperature, °C WABT, °C first hydrotreating reactor inlet pressure, kg/cm2 second hydrotreating reactor inlet pressure, kg/cm2 second hydrotreating reactor outlet pressure, kg/cm2 hydrogen/oil ratio, Nm3/m3 FCC feed hydrotreater yields, % gas naphtha diesel stable hydrogenate (hydrotreated heavy VGO) H2S conversion 360 °C+a sulfur in stable hydrogenate, %
1.2 347 370 375 366 49.2 47.1 44.5 310
1.2 356 379 384 375 49.2 47.1 44.5 310
1.2 368 388 391 383 49.4 47.3 44.2 310
1.2 374 397 399 391 49.4 47.4 44.3 310
1.2 350 376 381 371 49.0 47.0 45.0 310
0.27 0.30 6.41 91.42 1.6 6.3 0.0698
0.32 0.53 6.81 90.74 1.6 7.6 0.0454
0.42 0.39 7.25 90.34 1.6 10.8 0.0232
0.44 0.62 12.52 84.82 1.6 13.7 0.0175
0.36 0.36 6.51 91.17 1.6 6.5 0.0807
a Conversion is defined as (360 °C + feed - 360 °C + product)/360 °C + feed. 360° C + feed and 360 °C + product is determined by simulated distillation ASTM D-2887 of the feed and the unstable hydrogenate.
Table 4. Feed and Product Properties of the LNB FCC Feed Hydrotreater FCC hydrotreater feed HVGO reactor inlet temperature, °C
347
356
368
FCC hydrotreater product HTHVGO
374
347 stable
SG 15/15 °C S, % wt N, wt ppm H2S, % wt
0.9116 1.48 1166
0.9118 1.52 1185
0.9119 1.51 1134
0.9119 1.67 1139
0.8959 0.0698 764 0
unstable 0.21 0.15
356 stable 0.8945 0.0454 722 0
unstable 0.20 0.16
368 stable 0.8924 0.0232 582 0
unstable 0.19 0.18
374 stable 0.8913 0.0175 543 0
unstable 0.19 0.18
Aromatics 1 ring,% wt 2 ring, % wt 3+ ring, % wt total aromatics, % wt PNA PNA conversion, % wt nitrogen conversion, % wt
18.89 9.32 10.88 39.09 20.20
18.96 9.76 10.84 39.56 20.60
19.21 9.72 11.01 39.94 20.73
IBP 5% 10% 30% 50% 70% 90% 95% FBP Kw
255 343 362 404 436 469 511 525 542 11.9
297 345 363 404 435 467 509 524 542 11.9
302 347 365 405 436 468 509 524 542 11.9
18.28 9.54 11.27 39.09 20.81
26.6 6.13 5.75 38.48 11.88 41.2 34.5
26.44 6.45 5.83 38.72 12.28 40.4 39.1
26.23 6.77 5.98 38.98 12.75 38.5 48.7
25.32 6.71 6.38 38.41 13.09 37.1 52.3
distillation ASTM D-2887, °C 298 343 361 402 434 467 509 524 542 11.9
304 350 367 406 435 467 508 523 542 12.1
138 311 342 392 426 460 505 521 542
298 346 364 403 433 464 506 521 542 12.1
102 302 340 391 424 457 502 519 541
291 342 359 400 429 460 503 519 541 12.1
103 278 328 386 421 454 500 517 541
294 343 361 400 429 461 504 520 541 12.1
102 255 312 378 414 450 498 515 541
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Table 5. FCC Yield Distribution, Product Sulfur Content, and Properties of the Gasoline Obtained during Cracking of the Pure HTHVGO and the HTHVGO Mixed with H2S at the LNB FCC Unit FCC feed hydrotreater reactor inlet temperature, °C FCC feed
H2S in the FCC feed, ppm sulfur in the HTHVGO, ppm total sulfur in the FCC feed FCC products
347
356
368
374
350
70% stable HTHVGO/30% unstable HTHVGO 455 698 1126
66% stable HTHVGO/34% unstable HTHVGO 550 454 972
69% stable HTHVGO/31% unstable HTHVGO 558 232 757
65% stable HTHVGO/35% unstable HTHVGO 643 175 780
100% stable HTHVGO
100% stable HTHVGO
100% stable HTHVGO
0 807 807
0 620 620
0 304 304
yields, % S in yields, % S in yields, % S in yields, % S in yields, % S in yields, % S in yields, % S in % wt products % wt products % wt products % wt products % wt products % wt products % wt products
dry gas PPF BBF gasoline (ASTM D-86 T90 ) 176 °C) LCO (210-300 °C) HCO (240-360 °C) slurry (300-530 °C) gas oil fraction (LCO + HCO + slurry; 210-530 °C) coke conversion
5.14 6.46 13.00 52.93
0.85
0.97
0.0022 0.0045
5.05 6.62 13.48 52.71
1.09
0.0014 0.0033
4.97 6.55 13.37 52.55
9.53 3.55 5.19 18.27
0.0690 0.3590 0.4340 0.2290
4.20 81.73
0.0214
0.9700
0.0010 0.0021
5.30 5.73 13.60 52.83
9.44 2.82 5.68 17.94
0.0585 0.3080 0.3490 0.1897
4.20 82.06
0.0190
0.3600
0.0009 0.0022
4.14 6.38 12.66 51.54
9.50 2.76 6.10 18.36
0.0453 0.2400 0.1780 0.1187
4.20 81.64
0.0180
0.0038
4.14 6.02 14.26 51.98
9.32 3.48 5.53 18.33
0.0333 0.1930 0.1670 0.1040
9.88 4.02 7.18 21.08
0.0727 0.2940 0.4610 0.2472
4.20 81.67
0.0176
4.20 78.92
0.0399
0.3000 0.0015 0.0029
4.14 6.35 13.88 52.54
0.1500 0.00066 0.0014
9.22 5.74 4.74 19.7
0.0500 0.1750 0.4200 0.1754
9.78 3.77 5.44 18.99
0.0184 0.1000 0.235 0.1036
3.91 80.31
0.0400
4.20 81.01
0.0152
Gasoline Properties SG 15/15 °C N, wt ppm
0.741 45.1
0.743 39.8
0.741 36.7
1 ring, % wt 2 ring, % wt
27.7
