Q&A

(2016) Question 39: Please summarize the current status of slurry hydrocracking technology commercialization.

Slurry hydrocracking technology has been commercialized in China (VCC) and Italy (EST) in the past two to three years. Both facilities have demonstrated expected performance, including conversion and selectivity. The reliability of slurry hydrocracking is still an open question as these units have only been in operation for a short time. Additional VCC commercial units are scheduled for startup in the next 12 months.

(2016) Question 40: As it relates to overall catalyst cycle life management, please address the following issues: What are typical cascading practices for catalyst reuse after regeneration and eventual disposal that you employ? What quality control, catalyst properties and performance specifications, and/or warranties do you have in place for regenerated catalysts? What are some of the key decision criteria you use in determining whether to send a catalyst for metals reclamation, r

First, a response to the question: What are typical cascading practices that you employ for catalyst reuse after regeneration and eventual disposal? As the leading catalyst regenerator, Eurecat sees NiMo and CoMo hydrotreated catalysts (regenerated and regenerated plus rejuvenation) in ULSD, jet, kerosene, naphtha, and gas oil hydrotreating units.

(2016) Question 41: What are the considerations you use for extending hydrogen plant catalyst life cycles (i.e., lower production rates, furnace tube failure, etc.)?

There are many parameters affecting the hydrogen plant catalyst life cycles, such as lower production rates, furnace tube failure, unplanned plant shutdowns, larger catalyst volumes, elevated energy consumption, and finite ZnO/S (zinc oxide/sulfur) capacity. Lower Production Rates will obviously result in longer catalyst lifetime due to a lower gas velocity over the catalyst.

(2016) Question 67: As distillate demand has decreased, current economics favor maximizing gasoline and octane. What operating and catalyst changes do you recommend for increasing octane barrels?

An FCC unit contributes to the gasoline pool through both cracked gasoline production and C4s production, which is used to generate high octane alkylate for blending.

(2016) Question 68: What is your experience with processing raw crude in the FCC? What types of crude have you tried to process in the FCC? What are the yield impacts? Any corrosion issues associated with this mode of operation? What additional corrosion monitoring is needed?

I have not had any experience running raw crude directly into an FCC unit; however, I know there are refiners out there that do. Many refiners who are running a high percentage of tight oils into their crude units have found that there is typically a shortage of FCC feed, which has led to some of them charging tight oils straight into the FCC.

(2016) Question 69: Our FCC unit is limited by coke burn and high regenerator temperatures. What catalyst and operational changes have you implemented to maximize the conversion of heavy feeds and increase the amount of resid we can process without running into our regenerator limits and increasing dry gas production?

Considering the stated goals and constraints, particularly being limited by regenerator temperature and coke-burning capacity, it will be necessary to reduce delta coke without significantly increasing the reactor heat demand.

(2015) Question 29: What are the likely causes for temperature excursion events in a hydrogen plant?

Hydrogen plant temperature excursions are possible in several of the catalyst vessels and are usually observed in association with the water/gas shift reaction. During normal operation, the high, medium, and low temperature shift reactors display an exothermic reaction.

(2015) Question 30: What factors influence your decision to conduct air versus inert reactor entry for catalyst changeout? For, what methods do you use to avoid stress corrosion cracking?

For us to enter a reactor that is under an inert atmosphere, the conditions need to warrant it, such as when there are large amounts of pyrophoric material still present, when a specific job is required, an old catalyst needs to be vacuumed out for sampling purposes, or if there is filtration material on top that requires removal in order to allow the catalyst below to dump freely.

(2015) Question 31: What are your current safe practices for sour water monitoring? What are your preferred analytical methods/sampling frequency used to measure NH3/NH4HS (ammonia/ammonium bisulfide)?

The primary concern with sour water sampling is exposing operators to H2S and ammonia, which will evolve off the liquid as it is collected into the sample bottle. Typically, most of our plants would take an approach of ensuring that the operator pulling the sample was in supplied air.

(2016) Question 70: What is your method for measuring naphthenic acid [TAN (total acid number)] in FCC feed? Is this method affected by VABP (volume average boiling point) or Concarbon (Conradson carbon) content? Do you have data that validates an appropriate integrity operating window (IOW) trigger level? If above the trigger level, what is your recommended corrective action (extra inspection, change crude/slate, etc.)?

In terms of TAN number, we typically recommend the standard test method UOP 565, which can be found through the ASTM (American Society for Testing and Materials) website.

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