Q&A

(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 16: What is the typical carbon monoxide (CO) concentration in the reformer net gas? How is the CO content measured? What are the potential effects to downstream units from the CO?

Carbon monoxide can form in reformer units as the hydrocarbon reacts with moisture under very low-unit pressure conditions. Typically, semi-regeneration reformer net gas would have nil CO and only a minimal amount in a CCR-type unit. I expect it to probably be on the order of 5 ppm (parts per million), though some units report routine measurements of 10 to 20 ppm CO in their net hydrogen off gas.

(2013) Question 17: How many continuous reforming operators have completed a catalyst change while the unit continues to operate? What variables should be taken into account when planning such a change?

HollyFrontier has two CCRs: one at Tulsa that was converted from a semi-regeneration reformer and one at Artesia. We have not done a catalyst change at the Tulsa refinery CCR, but we have done an online catalyst change at Artesia.

(2013) Question 18: What are some typical causes for high pressure drop across regenerator dust collectors in continuous reforming units? Is anyone using continuous blowback on the bags?

The obvious answer to the high-pressure drop would seem to be that you have too many fines on the bags. But realistically, why do you get too many fines? The causes could be that you waited too long to do the reverse jet blowing or, a less common cause, that you are getting hydrocarbon carryover which is causing the fines to clump together on the bags.

(2013) Question 19: How are refiners managing low-coke operations in continuous reforming?

There are two ways to address the issue: 1) try to increase the coke that you are making and 2) adjust the regenerator. It would be great if you could just adjust how much coke you are making. However, most of the time you are restricted in what you can do with the unit, given your octane targets and the feed flows and qualities are fixed.

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