Q&A

(2016) Question 12: What operating strategies do you employ to successfully regenerate catalyst in a continuous catalyst regeneration (CCR) unit with a carbon content in excess of 10 wt%?

The burn zone in a Honeywell UOP Platforming™ CCR Regenerator is designed for operation at 5 wt.% carbon on catalyst or about 5.25 wt.% coke at the design catalyst circulation rate. We find that most units can operate normally at coke levels 40% above the design (about 7.4 wt.% coke) and some at even higher levels of coke.

(2016) Question 13: When the regenerator in a CCR unit is shut down for an extended periodof time, how do you predict coke on catalyst with no catalyst circulation?

There are two broad scenarios which might result in the catalyst circulation of a CCR Platforming™ unit being stopped for an extended period of time. The first is that there is maintenance being performed that requires the regenerator to be taken off-line for several days.

(2016) Question 14: Do you have experience with CCR heel catalyst contaminating the circulating inventory during operation? How can this contamination be prevented?

The most common situation that results in the contamination of a catalyst load with heel catalyst occurs during a turnaround as a result of accidentally reloading drums of used catalyst that contain heel catalyst back into the reactors. This type of contamination occurs in one or two units every year.

(2016) Question 15: How do you remove the CCR heel catalyst from the unit during an outage and underwhat atmospheric conditions?

Catalyst unloading from a CCR Platforming™ reactor stack is done under nitrogen atmosphere using the normal catalyst transfer line under the catalyst collector. Typically, the last 10 to 15% of the catalyst unloaded will be contaminated with heel catalyst. This percentage may be higher if there has been damage to internals or blockage of catalyst transfer lines.

(2016) Question 16: What is your Best Practice for inspecting and preventing erosion in CCR lift lines?

In CCR Platforming™ units, the movement of catalyst through the lift pipe results in contact between the catalyst pills and the inner surface of the lift pipe.

(2016) Question 42: What are your typical H2S (hydrogen sulfide) detection and monitoring methods used on heavy oil fractions being transported via truck, rail, or barge? What are the mitigation options you employ?

We see typically dragger tube testing and head space H2S monitors being used. Mitigation is still done, for the most part, with chemical additives. The most commonly used additives are from the triazine family. As a result of the concerns that refiners have with some of the existing triazine and non-triazine (e.g., glyoxal) being used with respect to the impact on downstream equipment, Nalco Champion has developed both non-triazine, non-acidic (non-glyoxal), and low nitrogen alternative H2S scavengers.

(2016) Question 43: Have you experienced high corrosion rates in carbon steel piping in resid service operating below 500°F? Please comment on corrosion mechanisms.

High corrosion rates have been experienced in heavier streams, like RCO (reduced crude oil) and vacuum residue operating at a temperature of 450 to 600°F. The role of naphthenic acid corrosion is difficult to determine in such streams with respect to the TAN (total acid number) distribution, temperature and velocity. The key precursor is sulfur species which causes “sulfidic corrosion” in such residue streams.

(2016) Question 17: What are your strategies for managing feed sulfur to reforming units? What are the pros and cons of the different approaches?

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.

(2016) Question 18: The increased production of light straight-run (LSR) from crude units is likely to have an impact on refiners’plans for Tier 3 compliance. What strategies do you employ in order to manage this issue?

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

(2016) Question 19: What range of sulfur targets for hydrotreated FCC gasoline do you anticipate for Tier 3 operation?

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.

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