Q&A

(2013) Question 34: When processing cracked naphtha, what is done to ensure that polymerization of the diolefins/olefins will not result in pressure drop problems in a reactor or upstream equipment?

Again, we are trying to prevent the polymerization of the olefin/diolefin. The primary concern is trying to prevent contact with oxygen because that will ultimately lead to gum formation. So, the preference would be, if possible, to feed this hot to all the downstream units and avoid intermediate storage.

(2013) Question 35: When processing tight oil crudes, are lower bed pressure drop problems in VGO/resid hydrotreater reactors a concern? If so, what mechanisms explain this issue?

The highly paraffinic nature of the tight crudes and the destabilization of asphaltene molecules can cause precipitation and agglomeration. One of our customers with a gas oil mild hydrocracker switched feedstock to increase amounts of black wax crude. This was a five-reactor system.

(2013) Question 36: Has the increased use of tight oil crudes and western Canadian crude been correlated with increased metals and solids in diesel, gas oil or vacuum resid?

The FHR CC (Corpus Christi) refinery has not seen an increase in raw crude filterable solids. With the increased domestic crude rates, we typically run about 20 to 50 pounds per thousand barrels with these occasional spikes to 100. We have recently started monitoring the filtrate from the 0.45-micron test with 0.1-micron paper.

(2013) Question 37: How does the increased processing of tight oil (Eagle Ford, Bakken, etc.) affect hydroprocessing operations? With lighter feeds and less sulfur, how can the hydroprocessing reactors and catalyst systems be tailored to optimize performance? What other factors in economics replace volume gain when processing these lighter feeds (i.e., impact on FCC yields, gasoline blending, minimizing cetane giveaway, etc.)?

Tight oil crudes have impacted our hydrotreater operations in several ways. Catalyst lifecycles are extending due to the low severity required for treating low-sulfur feed. Low reactor severities have caused emulsion problems due to our not hydrogenating our surface-active compounds in the feed.

(2013) Question 38: Elaborate on the relative value of the various distillate feed streams in a refinery (i.e., straight-run diesel, light atmospheric gas oil, light vacuum gas oil, light cycle oil, coker distillate, kerosene, coker naphtha, heavy cat naphtha, and other) when considering maximum saturation and volume swell in high-pressure ULSD service.

The question asks specifically about high-pressure ULSD service. ‘High pressure’ means the reactor has to operate around 1,000 pounds without any problem supplying hydrogen to these units. The relative value of the volume swell depends on how much you can saturate aromatics. This aromatic saturation is an equilibrium reaction, so you need high hydrogen partial pressure on the lower temperature side.

(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.

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