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STEVENPHILOON (Honeywell UOP)

It is desirable to have a small amount of sulfur in the feed for CCR reforming units in order to reduce the risk of metal catalyzed coke (MCC) formation and heater-tube carburization and dusting. The sulfur interacts with the chromium and the iron to form a protective layer that reduces the penetration of carbon into the metal. However, sulfur is also a poison to the platinum metal function of reforming catalyst; so, the amount in the feed must be kept below the level where it will impact the performance of the catalyst.

The recommended level of sulfur in the feed to a CCR Platforming™ unit varies depending upon the severity of unit operations. The risk of MCC formation increases with decreasing reactor pressure and increasing product octane.

Honeywell UOP’s recommended approach is to operate the naphtha hydrotreating (NHT) unit to remove essentially all of the sulfur in the feed. Thisapproachwill ensure that other contaminants (nitrogen, metals, oxygenates, etc.) are also removed from the feed to the extent achievable by the NHT.Organic sulfur is then added to the Platforming™unit feed with a chemical injection system pumping in a specific and controlled amount of organic sulfur compound to achieve the target recommended by the licensor. This injection of sulfur provides the refiner with independent control of the sulfur in the feed to the unit that can be changed,as needed,if feed rate or operating conditions change

JEFF BRAY (Honeywell UOP)

Tier 3 drives hydrotreating of essentially all light naphtha streams. Since most United States refineries have FCCs, it is usually desirable to hydrotreat other gasoline streams more completely to minimize the FCC naphtha olefin saturation and the associated octane loss. Even streams such as alkylate, and butanes can contain sufficient sulfur to impact the pool. Complete hydrotreating of these streams will often require additional hydrotreating capacity. With the increase of light straight-run naphtha yields from crude and the availability of cheap natural gasoline, many sites have become limited in hydrotreating capacity for the gasoline range streams. The regulatory requirement then drives an expansion of hydrotreating, which is very hard to avoid without significant impact on site economics. To make the project add to the site profitability, a key aspect is to try to extend the project not only to just meeting regulatory needs, but also to debottleneck the site so that more material, such as natural gasoline or other condensates, can be upgraded or value added in other ways.

JEFF BRAY (Honeywell UOP)

The sulfur target for hydrotreated FCC gasoline is very site dependent. But where possible, it is desirable to hydrotreat all other gasoline streams fully so that the FCC naphtha can be treated as mildly as possible. Deeper desulfurization for FCC naphtha results in increased olefin saturation with the resultant octane loss. Since the other gasoline streams can be hydrotreated without this reduction in stream value, hydrotreating of FCC naphtha should be done to the lowest level possible.

Within the structure of the Tier 3 rules, the flexibility to manage the yearly average sulfur provides some flexibility for operating the FCC hydrotreating at a constant degree of desulfurization needed to drive the yearly average to 10 ppm while also ensuring that the batch limit of 80 ppm is met. In practicality, it is probably better to target a sulfur level, as long as the conditions required to achieve that do not become too severe. Target levels will vary depending on the amount of FCC naphtha in gasoline and the sulfur levels of other blend streams, but these sulfur levels are expected to be in the range of 15to 35 pp.

The reduction of the sulfur target can require different strategies for the hydrotreating of the FCC streams. Many sites separate the lighter, higher olefin FCC gasoline from the heavier, more aromatic cut. The heavier cut goes through a more intensive hydrotreating, while the lighter stream is either blended or processed with technologies like extractive Merox™ treating to avoid olefin saturation. This treatment may not be sufficient to meet Tier 3specifications in all cases. If not, further processing of the light material will be required, resulting in more olefin saturation. This saturation, in turn, may drive the need for higher octane generation in other gasoline streamsto replace the octane loss from FCC naphtha hydrotreating.