Q&A

(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.

(2016) Question 20: When is it appropriate to neutralize austenitic stainless-steel equipment to protect against stress corrosion cracking (SCC)? What neutralization procedures and methodologies do you recommend?

Austenitic stainless steels (200-and 300-series steel) are the most common type of stainless steels. Austenite refers specifically to the geometry of the steel (face-centered cubic crystal). These types of steel are most typically recognized as non-magnetic. Austenitic steels are widely used in the industry because they have very desirable mechanical properties. Their austenitic structure is very tough and ductile down to absolute zero. They also do not lose their strength at elevated temperatures as rapidly as ferritic iron base alloys.

(2016) Question 21: What programs or systems do you employ to monitor hydrotreater furnaces and prevent tube failures and loss of containment? Can you share your experiences using technologies to implement online temperature monitoring of tube skin temperatures?

In nearly all hydroprocessing heaters, MPC has installed tubeskin thermocouples in order to provide continuous monitoring of tube metal temperatures to the DCS (distributed control system) operator. These thermocouples are strategically located in the heater at the areas with the highest estimated maximum heat flux.

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