Catalytic answer to a steam cracking challenge

Rapid growth in steam cracker capacity has encountered a developing problem – contamination of opportunity naphtha feed by carbon disulphide.

Marie-Clotilde Gouvenot and Yoeugourthen Hamlaoui

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Article Summary

Ethylene is the most used monomer in the petrochemical industry, employed as feedstock in several manufactures. Over the past few years, global ethylene demand has grown rapidly. Asia, the Americas, and the Middle East have been leading new ethylene capacity addition in the past decade. For the upcoming decade, China plans to continue leading ethylene growth, with new steam crackers popping up around the country. North America has also invested heavily in new cracker projects in recent years due to an advantage in ethane feedstock supplied. Facing this unprecedented competition, current ethylene producers are exploring several options to improve their competitiveness:
•    Revamping ethylene capacity
•    Improving refining and petrochemical integration
•    Using feedstock flexibility with diesel, crude, gas, or naphtha
•    Using new feedstock sources

Opportunity feedstocks offer a main advantage of lower cost. However, each advantage often has a counterpart; these feedstocks come with disadvantages. Among these disadvantages, one has been identified over the years as a strong contaminant for downstream catalysts, carbon disulphide (CS2).

From well to steam cracking furnace
More and more petrochemical actors are facing high CS2 content in the feedstock for their naphtha steam crackers, and this tendency is expected to increase in the coming years. Indeed, crude wells are ageing and, as a consequence, more H2S and heavy materials like asphaltenes/paraffins are present, making crude oil extraction more difficult.

H2S could be an issue for personnel safety in case of exposure during extraction or even during transportation. H2S scavengers employed, such as triazine, amines, or formaldehydes, react with the carbon in crude oil to form complexes. See Figure 1 for example.

In the furnace, these complexes are cracked to form CS2.

‘Heavy’ hydrocarbons present problems for crude oil transportation or storage and, depending on their content, plugging can occur in the wellhead and in storage. CS2 is then used as a flow improver and found in steam cracker furnaces.

It would appear that CS2 issues could be directly related to the naphtha source. Indeed, when importing naphtha from Brazil, Canada, Egypt, Kuwait, Morocco, Russia, and the US, operators often face this issue.

From cracking furnaces to downstream units
To understand where CS2 impacts the steam cracker operation, it is worth bearing in mind the boiling point of CS2. This boiling point is close to that of some hydrocarbons with five carbon atoms (see Figure 2).

Downstream of the stream cracker furnaces, several fractionation steps target recovery of C2 (acetylene, ethylene, and ethane), C3 (methylacetylene, propadiene, propylene, and propane), C4 (butadiene, butene1, butene2, butane, and sometimes vinyl acetylene), and the C5+ cut (heavier components including aromatics as benzene and toluene).

As a direct consequence, CS2 is found in the C5+ cut. The C5+ cut may be used at several stages for different purposes:
• The C5 cut can be fully hydrogenated in a total C5 hydrogenation unit to recycle the C5 stream to the steam cracker furnaces and hence increase light olefins yield.
• C5 can be used in an extraction unit to valorise the isoprene cut.
• C5+ can be treated as a pyrolysis gasoline (pygas) cut in a pygas hydrogenation unit to allow aromatics (benzene, toluene) recovery while removing the sulphur component.

Between the steam cracking furnaces and the C5+ cut, the CS2 content becomes concentrated.
Therefore, 4-5 wtppm of CS2 in the naphtha feedstock will lead to 20-25 wtppm of CS2 in the pygas feed, considering typical pygas yield on the naphtha cracker (see Figure 3).

This explains how CS2 has been identified by comparing the lack of catalyst activity observed in C5 total hydrogenation and pygas hydrogenation with the origin/nature of the naphtha feedstock.

CS2 impacts
Pygas feed may contain up to several hundred parts per million of sulphur. Speciation of sulphur, including CS2, has highlighted the presence of thiophenes (80 wt% of the total sulphur species), mercaptans/sulphides/disulphides (15 wt%), CS2 (5 wt%), and H2S/COS (below 0.5 wt%).

These sulphur species have different poisoning effects on the catalyst used in C5/pygas hydrogenation. Among the sulphur species described here, thiophenes present the lowest poisoning effect, followed by mercaptans, sulphides, and disulphides in ascending order. H2S/COS has the strongest poisoning effect and CS2 the second strongest poisoning effect.

The strong poisoning effect of CS2 has been observed in industrial units and confirmed by pilot tests.
Indeed, in the presence of a few ppm of CS2 in the pygas feed, a reactor temperature increase is required to compensate the catalyst deactivation.

A pygas unit comprises two stages. The first stage targets complete removal of diolefin and styrenic components while the second stage aims at the complete removal of sulphur and olefin components while ensuring lower aromatics losses.

Figure 4 shows industrial feedback from a first stage pygas unit operated with a palladium based catalyst. This unit encounters CS2 inhibition on a regular basis. To the left, the position of the thermocouple is indicated in the catalyst beds. The reactor exotherm distribution per thermocouple is shown to the right.

This exotherm distribution provides an accurate picture of catalyst activity. Indeed, if the catalyst is not inhibited, the exotherm should be mainly present at the top part of the catalyst bed. If contamination is present in the feed, we observe catalyst activity shifting from the top part of the catalyst bed to the bottom part.

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