Q&A

(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.

(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.

(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.

(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%.

(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.

(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.

(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.

(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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