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(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.
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(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.
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(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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(2015) Question 32: What is your suggested minimum temperature required to achieve adequate metals removal in the demetalization (demet) catalyst to protect primary treating catalyst in FCC and hydrocracker pretreaters?

The suggested minimum reactor temperature required for adequate metals removal is going to be metals specific. For silicon, the temperature is definitely greater than 570°F; and for nickel and vanadium, we suggest greater than 600°F. Now higher reactor temperatures may be required for adequate removal, depending on the space velocity through the metal-strapping catalyst and whether or not there may be a tolerance issue with the primary treating catalyst.
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(2015) Question 33: Phosphorus-based chemicals are used to neutralize naphthenic acids. Drilling and completion fluids also can contain phosphorus, so it may be in crude oil. What are your Best Practices to protect active hydrotreating catalyst from phosphorus poisoning?

I am going to give a little background on phosphorous poisoning and then share one specific example we have seen in one of our refinery units. First of all, phosphorus is a strong catalyst poison. In our course materials, we say that 1% phosphorous on catalyst will reduce the activity by 50%.
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(2015) Question 34: Hydroprocessing reactor pressure drop can increase due to feed particulates, corrosion by-products and polymerization reactions. How can bed design and loading method be optimized to avoid pressure drop limiting the cycle length or throughput?

There are a lot of approaches to helping out with pressure drop problems in a reactor, and I will go through them. We use all of these at Phillips 66. I will start at the top. There are particulate catching trays. These are relatively new. We have had limited use with these, although we think they have been fairly successful.
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(2015) Question 35: What important parameters do you consider in designing a post-treat bed for a hydrocracker? What are the advantages and disadvantages between Type I and Type II catalyst when used as a post-treat bed in a hydrocracker?

The post-treat bed is generally positioned at the bottom of the reactor in a hydrocracking reactor, and its main purpose is to remove sulfur compounds that have recombined with the organic compounds coming out of the reactor. Usually, it is a function of olefins that are generated in a hydrocracking catalyst.
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(2015) Question 36: What has been your experience regarding selectivity and activity when using regenerated hydrocracking catalysts versus fresh catalysts? How do results vary with catalyst type, unit objectives, and conversion targets?

There are well-established track records for regeneration and the reuse of spent hydrocracking catalysts, depending on service history, catalyst type, and conditions in which the catalyst was recovered. These catalysts can be returned to fresh or near-fresh performance, in most cases, and often come back basically equivalent to fresh.
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(2015) Question 37: What are some of your strategies for managing as oil streams during outages of conversion units for refiners with vacuum gas oil hydrocracking and FCC units?

Obviously, the answer to this question is very site-specific depending on different options available based on refinery location and configuration. There are a couple of general options, and I will give one example. If you have an outage of a VGO processing unit in your refinery, one option would be internal processing.
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