Q&A

(2016) Question 75: In your experience, how does the shape of an FCC catalyst particle impact the fluidization properties of the catalyst? What other properties are important to monitor?

The key catalyst properties affecting fluidization are particle size distribution, particle density, and particle shape. Fluidization studies have shown that a change in catalyst shape from spherical to oblong gives a 19% reduction in deaeration rate, due to more drag force with an oblong particle: meaning, itis harder to defluidize this material. However, catalyst with irregular particles and sharp edges, such as attrition generated particles, are harder to unlock and fluidize.

(2016) Question 76: What FCC operating, and catalytic changes can lower gasoline sulfur while retaining octane? How would feed hydrotreatment impact these options? How would the FCC operate and catalytic changes impact gasoline post-hydrotreating?

Hydrotreating the entire FCC feedstock upfront will allow more flexibility in operation of the reactor/regenerator. Delta coke will decrease with a hydrotreated feedstock, which will lead to a colder regenerator and will drive a higher cat-to-oil ratio. Increasing cat-to-oil will directionally increase both gasoline yield and octane number.

(2016) Question 77: What are your Best Practices for mitigating operational or performance risks throughout a catalyst changeover?

It is understood that there are risks when changing catalysts. Objectives and constraints might change during the trial, or changes in operating conditions might skew expected performance.

(2016) Question 78: What operational and catalytic changes have you implemented to optimize C4 olefin yield for the alkylation unit?

A low REO of less than 1% can yield a higher C4 olefinicity compared to catalyst of higher REO at constant conversion. However, as conversion increases, C4 olefinicity will decline.

(2016) Question 79: What methods do you use to detect and monitor coke deposition in FCCU risers? What prediction methods have been successful?

While coke deposition in reactor void spaces and overhead lines has been reported with some regularity, coking in risers is less common. Increasing riser pressure drop and decreasing riser shell temperatures provide an indication of riser coking, but gamma ray scans are the surest online indication of riser coking.

(2016) Question 80: What is your Best Practice for removing feed nozzles during turnarounds when only the tips are planned to be replaced? Are there any pros/cons or advantages/disadvantages of removing the nozzles while the system is hot or after it has cooled?

All of these systems work well most of the time; but at times, there can still be problems extracting the nozzles from the sleeves. A common first line of attack in removing a nozzle from a sleeve is to utilize threaded holes in the nozzle flange that are used with “jacking screws "to break a nozzle loose after it is unbolted from the sleeve.

(2016) Question 81: What is your inspection Best Practices for third-stage separator (TSS) systems throughout a scheduled turnaround? What types of issues or equipment damage should be would you proactively anticipate in order to mitigate potential turnaround delays?

For TSS systems, it becomes important to start by monitoring the operating conditions and process velocities throughout long-term operation to help anticipate the extent of erosion and internal wear of the equipment. Some refiners track velocity hours for the individual cyclones or barrels while others simply track onstream time to help predict when some of the equipment may ultimately fail.

(2016) Question 82: Have any of your FCC units observed extensive corrosion in carbon steel piping operating below500°F, particularly in the slurry circuit? What are your typical corrosion mechanisms? What metallurgies would you deem acceptable for high-temperature, high-sulfur streams?

We have not seen any issues with piping below 500°F. Sulfidic corrosion is the typical mechanism about which to worry with regard to hot streams containing sulfur, such as FCCU feed and slurry. API Recommended Practice 939C should be referenced for sulfidic corrosion.

(2016) Question 83: What are the variables you consider which impact slurry oil pump life? What is the typical slurry oil pump life that you experience in normal service?

Slurry oil pump life can be influenced by a number of factors including catalyst carryover from the reactor (which is indicated by BS&W measurements) and the design of the pump itself.

(2016) Question 84: What effects, if any, have you observed concerning slurry pump-around exchanger fouling when processing shale oil/tight oil feeds?

Our expectation would be that there could be issues on both the slurry side (tube side) of the exchangers and the shell side in FCC feed preheat service. Of the two, we would expect fouling on the feed side of a slurry/feed exchanger to be most impacted due to the waxy nature of shale oils with the propensity of paraffins to undergo thermal cracking to form coke in high temperature services.

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