OLEFINS CAN LIMIT DESULFURIZATION OF REFORMER FEEDSTOCK

July 3, 1995
Syed A. Ali , Jamal A. Anabtawi King Fahd University of Petroleum & Minerals Dhahran, Saudi Arabia Pilot plant studies have shown that the presence of even very small amounts of olefins may limit the desulfurization of reformer feedstocks to trace levels.
Syed A. Ali, Jamal A. Anabtawi
King Fahd University of Petroleum & Minerals Dhahran,
Saudi Arabia

Pilot plant studies have shown that the presence of even very small amounts of olefins may limit the desulfurization of reformer feedstocks to trace levels.

Engineers at the Research Institute of King Fahd University of Petroleum & Mineral observed under typical industrial conditions the recombination reaction of olefins with hydrogen sulfide to form mercaptans. The results indicate that the advantage of using highly active (third generation) CoMo hydrotreating catalysts can be masked by these reactions if the olefins are not saturated.

The trend in naphtha reforming is to use high-rhenium, bimetallic catalysts that display less resistance to Sulfur than do balanced Pt-Recatalysts. Due consideration, therefore, should be given to these undesirable recombination reactions while designing hydrotreaters and selecting hydrodesulfurization (HDS) and reforming catalysts.

Hydrotreating of naphtha is required to prepare the feedstock for catalytic reforming. This preparation step protects the expensive platinum-rhenium catalyst.

Hydrotreating reformer feedstock is common at refineries, and the selection of an appropriate catalyst for such an application seems straightforward.

Bench-scale evaluation of reformer feedstock pretreatment catalyst, however, is complicated because of: the accuracy of trace sulfur analysis (

Moreover, the recombination of olefins with H2S may confound the results. To explain this aspect, a detailed sulfur compound analysis was carried out in this study.

CATALYSTS, FEEDSTOCKS

Standard methods were used to characterize two CoMo hydrotreating catalysts for physical properties, chemical composition, and mechanical strength. The results, presented in Table 1,(17471 bytes) indicate that Catalyst B has a higher loading of molybdenum and cobalt oxides, and contains about 1.8% phosphorus oxide, which acts as a promoter.2

Although these results indicate the superiority of Catalyst B, performance with actual feeds and under commercial operating conditions is usually the criterion for catalyst selection.

Two types of feedstock were used: straight-run naphtha (SRN) and a blend of SRN and hydrocracked naphtha. To investigate the effect of HDS on the different types of sulfur compounds, the feedstocks and products were characterized for mercaptans (ASTM D-3227), disulfides (UOP-202), elemental sulfur (UOP-286), and total sulfur (ASTM D-4045).

The results, presented in Table 2,(19118 bytes) show that of the total sulfur in the SRN, 55.7% is mercaptans, 43.1% thiophenes and sulfides, and 1.1% disulfides. It also contains traces of hydrogen sulfide and elemental sulfur.

A Perkin-Elmer Model 8700 gas chromatograph (GC) equipped with a flame photometric detector (FPD) and a DB-I fused silica capillary column was used to identify the individual Sulfur compounds.3-5 The sensitivity of the GC/FPD technique was maximized by optimizing the gas flow rates and temperature programming.

This analysis showed the presence of 52 sulfur compounds, 17 of which were identified by matching retention times.

The DB-1 column elutes the sulfur compounds in order of increasing boiling point. This property was used to recognize an additional 24 sulfur compounds. The identified sulfur compounds included: 9 sulfides, 3 disulfides, 12 mercaptans, 16 thiophenes, and 2 thiols.

Analysis of a commercial product naphtha (produced from the same blend naphtha as used in the study) shows the presence of four sulfur compounds: methyl mercaptan, isopropyl mercaptan, nbutyl mercaptan, and 2,3,4,5-tetramethyl thiophene.

The presence of 2,3,4,5-tetramethyl thiophene was expected because thiophenes, particularly those with four methyl groups, are known to be difficult to desulfurize. The presence of mercaptans, however, was not anticipated.

Their presence indicates the occurrence of the following recombination reaction:'

Mercaptan + H2S Olefin + H2 4 Paraffin

This reversible reaction, which shifts to the left at higher H2S partial pressure, also depends on temperature, feedstock type, total sulfur, partial pressure of hydrogen and olefins, space velocity, and reactor configuration.

CATALYST ACTIVITY

Activity tests were conducted in a fully automated, bench-scale unit designed for unattended operation. The experiments were designed to investigate the effect of temperature, space velocity, and hydrogen gas rate.

The catalysts were diluted with silicon carbide (2-3 mm size) to produce a 46-cm long catalyst bed in a 2.7-cm ID trickle-bed reactor. The catalysts were presulfided in situ using 1 wt % CS2 in SRN. Pure hydrogen gas was used in once-through mode and pressure was maintained at 400 psig.

The temperature profile inside the catalyst bed was monitored using three thermocouples and controlled by a five-zone furnace.

The activity tests were carried out for 48 hr after the steady state was reached. The liquid product stream from the reactor was condensed to 10 C. in a gas-liquid separator, then immediately stripped of dissolved H2S by extraction

with acidified cadmium chloride solution.

The gaseous products were analyzed periodically using a refinery gas analyzer.

TEMPERATURE EFFECT

The HDS performance data for the two catalysts are presented in Table 3.

For blend naphtha and Catalyst A, the total sulfur decreased from 72 ppm at 220 C. to a minimum of 0.69 pp at 300 C. Upon further increase in temperature to 350 C., however, total sulfur increased, as shown in Fig. 1(44392 bytes).

The mercaptan concentration-about 56% of the total sulfur in the feedstock-wa reduced to about 6% at 2200 C. then increased to about 36% a 300 C. and to about 57% a 350 C. This indicates the occurrence of mercaptan forming reactions at temperatures greater than 300 C. along with removal of other types of sulfur.

A similar observation wa made be Sekhar and Rahimi while hydrotreating naphtha derived from coal liquids an heavy oil.

Although similar trend were noted for Catalyst B lower total sulfur and significantly higher mercaptan sulfur were observed, compared Catalyst A. The mercaptan constituted about 13% of the total sulfur at 220 C. an increased with temperature to 80% at 350 C.

It can be inferred that Catalyst B has higher HDS activity but favors the formation o mercaptans by H2S-olefin recombination reactions. The greatest HDS level occurred a 300 C. for both catalysts, suggesting that HDS is not dependent on the catalyst used.

GC/FPD results indicate that the product obtained wit Catalyst B at 250 C. contained 12 sulfur compounds: 3 mercaptans, 2 sulfides, and 7 thiophenes. At temperature greater than 280 C., thiophenes were removed almost completely, but mercaptan were still present, suggesting their formation resulted from recombination reactions.

HDS units, therefore should be operated at the lowest possible temperature to minimize mercaptan formation.

SPACE VELOCITY

For SRN and Catalyst A at 250 C., total sulfur increased from 26 ppm, to 41 ppm as the space velocity increased from 10 hr-1 to 13 hr-1 (Table 3)(41733 bytes). Meanwhile, the mercaptan concentration increased from 0.8 to 2.2 ppm. At temperatures over 280 C., greater space velocity inhibits mercaptan-forming reactions, as shown in Fig. 2(43424 bytes).

The effect of hydrogen addition rate on HDS was insignificant between 67 and 80 normal cu m/cu m, as shown in Table 3(41733 bytes). Its effect is more pronounced at lower space velocity, and higher addition rates increase desulfurization and suppress H2S_ olefin recombination reactions.

FEEDSTOCK EFFECT

Results related to the effectiveness of Catalysts A and B for desulfurization of SRN and blend naphtha show that SRN is easier to desulfurize. With blend naphtha, the minimum total sulfur of 0.69 ppm was obtained at 320 C., while with SRN, the minimum was 0.37 ppm at 300 C.

At temperatures greater than these., the occurrence of H2S-olefin recombination reactions increased total sulfur for both feedstocks, as shown in Fig. 3 (44414 bytes).

Recombination has been reported for SRN at temperatures of 320-326 C., and for cracked naphtha at about 320 C. These temperatures depend on process conditions and catalyst type (CoMo or NiMo).

Nickel-molybdenum catalysts are known to reduce recombination reactions by hydrogenating olefins. At

higher temperatures, however, very active catalysts can cause cracking near the reactor outlet, producing olefins.

CATALYST PERFORMANCE

A definite superiority in HDS activity was observed for Catalyst B at all temperatures, as shown in Fig. 4(42972 bytes). The reader should be reminded that Catalyst B has higher loading of molybdenum and cobalt oxides than Catalyst A, and contains about 1.8% phosphorus oxide.

Stanulonis and Pedersen reported that the presence of Phosphorus in hydrotreating catalysts may result in a variation in acidity.2 This variation, similar to that caused by cobalt in molybdenum/alumina, is reported to improve the desulfurization and denitrogenation activity of the catalyst.

Catalyst 13, as a result of its acidity, exhibited greater hydrocracking and olefin production, thus promoting recombination reactions at higher temperatures.

Parted String Calculation Results chart (52347 bytes)

RECOMMENDATIONS

Although naphtha is routinely hydrodesulfurized at refineries, there is room for improvement.

The results of this study confirmed the occurrence of H2S-olefin recombination reactions via detailed analysis of sulfur compounds. Product sulfur decreased to a minimum, after which increasing temperatures enhanced mercaptan formation. This minimum was found to be a function of sulfur concentration in the feed.

On the basis of characterization and performance data, Catalyst 8 was found to be better because of its higher oxide loading and the promoting effect of phosphorus. The undesirable mercaptan formation, however, could not be eliminated.

Hydrogenation of olefins, therefore, should be considered when designing newer hydrotreating catalysts. Such a step surely would result in deeper desulfurization and improved performance of downstream reforming catalysts. The authors recommend using NiMo catalyst in the top 10-15% of the hydrotreater, with CoMo catalyst in the remainder of the reactor. Using this combination, olefins will be hydrogenated before HDS, and recombination is avoided, even at temperatures greater than 300 C.

ACKNOWLEDGMENT

This work is part of KRUPM/RI Project No. 21101, sponsored by a refinery in Saudi Arabia. The authors wish to acknowledge the support of the Research Institute of King Fahd University of Petroleum & Minerals.

REFERENCES

1. Kellet, T.F., Sartor, A.F., and Trevino, C.A., "How to Select Hydrotreating Catalyst," Hydrocarbon Processing, May 1980, p. 139.

2. Stanulonis, J.J., and Pedersen, L.A., "The Effect of Phosphorus and Other Promoters on CoMo/Alumina Hydrotreating Catalysts," Proc. Symp. on Novel Methods of Metal and Heteroatom Removal, Mar. 23-28, 1980, Houston.

3. Farwell, SO., and Barinaga, C.J., "Sulfur-Selective Detection with the FPD: Current Enigmas, Practical Usage and Future Direction," J. of Chromatographic Science, Vol. 24, 1986, p, 483.

4. Hyver, K.J., and Diubaldo, D., "Analysis of Sulfur Compounds in Naphtha by Capillary Gas Chromatography and Flame Photometric Detection," Hewlett Packard Gas Chromatography Application Brief, 1986

5. Hutte, R.S., Johansen, N.C., end Legier, M.F., "Column Selection and Optimization for Sulfur Compound Analysis by Gas Chromatography,11 J. of High Resolution Chromatography, Vol. 13, 1990, P. 421.

6. Satchell, D.P., and Crynes, B.L., "High olefins content may limit cracked naphtha desulfurization," OGJ, Dec. 1, 1975, p. 123.

7. "NPRA Q&A - 1: Refiners probe hydroprocessing operations," OGJ, Apr. 2, 1984, p. 107.

8. Sekhar, M.Y.C., and Rahimi, P.M., "Upgrading of Coprocessing Naphtha by Hydrotreating," Advanced in Hydrotreating Catalysts, 1989, p. 251.

9. NPRA Q&A - 1: Catalysts get concentrated attention", OGJ, Feb. 27, 1989, P. 82.