Q&A

(2011) Question 43: In order to meet RMACT 2 regulations for reducing regenerator vent gas HCl and Total Organic Carbon, some refiners use caustic scrubber vent gas wash tower systems for treating the regenerator vent gas. What has been your experience with respect to corrosion problems? Which equipment (Venturi scrubber, wash tower) and piping have corroded more often? What changes have been made in procedure and/or metallurgy to minimize corrosion?

We have three CCRs with vent gas scrubbers; all are carbon steel, and all have experienced corrosion problems.

(2011) Question 44: What are the operating parameters, including water or chloride additions, to adjust and monitor on a continuous catalytic regeneration reforming unit when it is required to operate for a short period of time (hours/days) with the regeneration section shut down (for instance if operating in low-coke mode)?

We have four CCR/Platformers in our refineries. While two operates for gasoline production, one operates in mix mode i.e., for BT as well as for gasoline production. The other solely operates for para-xylene production.

(2011) Question 45: What tools are you using to predict the yields of Xylene, Benzene, Toluene and other aromatics in a catalytic reformer? What methods do you use and how often do you test the feedstock for these variables? Other than feedstock quality, what factors are you accounting for in the individual yields (unit pressure, RON, etc)? Do you have any rules of thumb for conversion of certain species of aromatics?

Dedicated simulators are run for prediction, either using correlations or kinetic models. To be able to perform accurate predictions, feed analyses shall be performed every time the feedstock quality is changed: the most important one is detailed hydrocarbon analysis by gas chromatography (for instance Carburane).

(2011) Question 46: Ethanol blending, and benzene management has shifted refinery octane and hydrogen balances. How are you managing hydrogen demand without giving away octane? Conversely, how are you, with excess hydrogen, maximizing availability for volume swell?

Mandated ethanol blending and limits on benzene in gasoline tend to lower the ceiling on the operating severity of catalytic reformers. While lower severity operation is theoretically desirable, in practice it can constrain H2 production, and impact regenerator operation due to lower coke make, which may require operational workarounds.

(2011) Question 47: What success have you had with installing stabilizer feed chloride treaters in reducing the salt formation and frequency of water washes?

The use of promoted alumina versus zeolite in the liquid chloride treating has several issues. For aromatics operations a Zeolite chloride treater should be selected to protect the downstream aromatics solvent from organic and inorganic chloride.

(2011) Question 48: How does naphtha derived from tar sands and shale oil differ in respect to crude oil-based naphtha? What is the impact on reformer operation?

It is assumed that “shale oil” as mentioned in the question refers to oil produced from hydraulic fracturing of shale reservoirs, as opposed to oil produced from “oil shale” rock via retorting or other techniques.

(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.

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