Q&A

(2013) Question 39: There is a drive to target the highest endpoint possible on all distillate feed streams when maximizing overall diesel production. Are there feed streams that should be targeted first, considering operational impacts of such optimization, impacts to catalyst performance and life cycle, as well as cutpoint optimization between distillate units and the FCC?

For maximum diesel, in general, we prefer getting the distillate out of the FCC. I think we had a discussion last year in the FCC forum during which we said that keeping some distillate in the FCC feed is a benefit. We still say that if you want to maximize the diesel, heavy-out the straight-run distillate of virgin gas oil because it will be the easiest to treat compared to the other two, which are coker distillate and LCO.

(2013) Question 40: Economic drivers dictate the need to process more difficult feedstocks, such as cracked stocks and diesel feeds with high distillation endpoints. What are typical guidelines regarding minimum hydrogen partial pressure for a given feedstock? (High-level answer with details will be discussed in the Hydroprocessing P&P.)

We are treating feedstocks with higher endpoints and greater volumes of cracked feedstocks. Certainly, you are faced with refractory sulfur species that are harder organic nitrogen compounds, which then inhibits sulfur removal and polyaromatics. Higher hydrogen partial pressures are required to achieve diesel specifications and maximize catalyst life in a conventional treater.

(2013) Question 41: In an effort to increase margins on hydrotreating units, what strategies and/or new technologies are refiners employing to minimize utility usage? What are the economics and reliability of adding a power recovery turbine?

In the IsoTherming® liquid hydrotreating process, there is a substantial reduction in utilities on a unit we just started up with 40% straight-run/60% light cycle oil.

(2013) Question 42: Occasionally we make off-color jet (pink, blue, or green). What are the causes, and what can be done to correct this?

The question was specific to off-color jet, but we can have other off-color material. We have seen red, yellow, green, and brown. Most typically, the yellow and green tend to be associated with the lighter products, red and brown with the heavier ones. But again, you can get various colors throughout the spectrum.

(2013) Question 43: Can FCCU feed pre-treatment achieve the new Tier 3 gasoline sulfur targets without post-gasoline treatment? What criteria are used to select the optimal combination of pre-treatment and post-treatment severities to meet the Tier 3 objectives?

For Tier 3 gasoline, the anticipated average of 10 ppm sulfur will be required by 2017. In order to understand what will be needed to meet those specs, you will have to do a review of a number of factors that contribute to the sulfur, including understanding your crude diet and the material that is actually going into the gasoline pool, as well as blend components.

(2013) Question 44: What are refiner’s practices or procedures to remove catalyst from a reactor when the catalyst will not free flow dump? What is the industry's experience with hydro drilling for removal of non-free-flow catalyst from fixed-bed units?

We typically vacuum out catalyst in an inert atmosphere if the reactors do not free-flow dump. We also wet dump some of our reactors, which involves vacuuming out the catalyst after removing the water. For people who are involved in turnaround planning, unloading rates for free-flowing catalyst are approximately 200 cubic feet of catalyst per hour.

(2013) Question 45: What are the procedures/rules governing the transportation and disposal of catalyst contaminated with arsenic, mercury, barium, or other heavy metals? Are there maximum limits for any of these?

The spent catalyst needs to be shipped offsite and sent for metals reclamation or disposal. If it is going for disposal, it will have to be characterized to determine if 1) it is a hazardous waste, which it is most of the time, and 2) it meets the applicable Land Disposal Restrictions (LDRs). It would have to be treated, as part of disposal, to meet the LDRs.

(2013) Question 96: What are the typical causes of dipleg plugging/fouling? How can the plugging/fouling be avoided? What is the experience with clearing diplegs online?

I am going to take the question in a few parts. I will cover the reactor side first. In the reactor side, dipleg plugging will generally be due to coke formation that can be subdivided into two categories: the coke formation that occurs either internal to the cyclone or externally. On the gas outlet tube of the cyclone, you will see the stereotypical coke formation on the backside of the gas outlet tube, perhaps from incomplete feed vaporization.

(2013) Question 97: What operational or design changes can be employed to address heat balance issues – e.g., catalyst circulation limits, low regenerator temperatures –associated with processing tight oil-derived feeds?

This answer will be very similar to what was already discussed about how to treat the resids. The example shown on the slide is a Maya blend, a typical tight oil, and then a tight oil with resid. Again, we are seeing significant reductions in sulfur and Conradson carbon metals and also a much higher hydrogen content.

(2013) Question 98: What catalyst changes can be made to minimize the negative effects of low delta coke that result from processing increased amounts of tight oil-derived FCC feed?

The schematic on the slide shows the representation of the coke yield and the coke balance from the FCC. Of course, the total overall weight percent coke yield is set by heat balance, but the sources of the coke vary significantly from one feed to the next. Everyone talked thoroughly about how the coke precursors are just not there in these lighter feeds.

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