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(2013) Question 22: What considerations in caustic scrubber operation or design are available to mitigate caustic carryover and corrosion? Discuss differences between various services.

Let’s quickly review some concepts for good caustic scrubbing, caustic strength (not just pH, but also the weight percent sodium hydroxide), contacting of the treat stream with the caustic using pre-mixing or submerged inlets, packing within the scrubber, and caustic circulation to keep the caustic uniform in concentration.
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(2013) Question 23: What are the operating strategies for C5/C6 isomerization units with current fuels regulations? Are units being run primarily for benzene saturation withchanges in operating parameters, feed sources, and treating being made to account for seasonal differences in gasoline pool RVP?

The answer is basically ‘yes.’ We are looking at isomerization units as benzene polishers for the light straight-run. Sometimes the light straight-run has too much benzene in it and a BenSat™ unit would be more appropriate for benzene conversion. The isomerization unit is an economic unit in the refinery.
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(2013) Question 24: For refiners who have naphtha splitter columns, either upstream or downstream of a hydrotreater, how many of these towers experience overhead corrosion issues? Has oxygen played a role in any experienced corrosion? What solutions exist to mitigate the issues?

As a preface to my answer, I thought it important to define what we see as a splitter versus a stripper. To us, a naphtha splitter is a simple fractionator vessel. It takes naphtha and separates it into a light fraction that goes to gasoline blending and a bottom, heavier fraction that goes to catalytic reforming.
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(2013) Question 25: What issues are encountered when introducing cracked naphthas into units that were not originally designed for the higher olefin content? What other contaminants should be considered when making this change in operation, e.g., silicon, nitrogen, and sulfur?

There are many potential issues. The single most obvious one is the heat released due to the olefins. You must make sure you can handle the heat release without coking up the reactor. You also have a higher risk of furnace fouling or coking in the furnace.
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(2013) Question 26: How will the ISO 8217 Marine Fuel Oil Hydrogen Sulfide (H2S) specification (less than 2 ppm H2S in the liquid phase) affect refiners? Do any refiners plan to implement the standard, and what procedural or equipment changes are likely needed in order to meet the specification?

Simply put, refiners will be required to meet the ISO 8217 2 ppm H2S specification if they are going to sell fuel oil to customers who have requirements to meet this specification. ISO 8217 is a fuel specification, not a regulation. A regulation is enforced by some regulatory organization.
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(2013) Question 27: What options are refiners considering addressing upcoming Tier 3 Fuel Standards [10 wppm (weight parts per billion) annual average sulfur in gasoline]?

Tier 3 fuel is lowering sulfur yet again in gasoline. The crude oil sulfurs have been coming down also with the tight oil, so some people have asked the question: Is processing more tight oil actually going to get us on-spec on Tier 3? The answer is no, not really. It is not going to have that significant of an impact on your gasoline sulfurs, obviously, without other processing.
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(2013) Question 28: Is the changing quantity of pentanes and pentenes in refinery streams and tightening gasoline regulations leading to operators considering different processing strategies in order to maintain gasoline blend pool specifications? Comment on increased pentene alkylation, decreased pentane isomerization, or other disposition sources.

The pentenes, also called amylenes, can be fed to the alkylation unit and be alkylated. However, you make a lot of ASO (acid-soluble oil) and the yield is not that great; so, most people prefer not to do it. We do not alkylate our amylenes at the moment.
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Question 11: What process or catalyst options are available for shifting yield selectivities from gasoline to distillate while minimizing the impact on light olefin yields? How are the product properties impacted? How does change-out rate impact the viability of the catalyst options?

Undercutting gasoline into light cycle is the first option and is widely employed. It is quick, it is easy, and it gives an immediate impact. Reducing riser temperature and/or cat-to-oil ratios reduces conversion, while using a ZSM-5 additive to regain C3-C4 olefins is another option.
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Question 13: With the move toward greater utilization of “opportunity crudes” such as Canadian synthetic crudes, what shifts do you expect in FCC product yield and quality, and how will this impact the operation of the FCC unit?

Holly’s choice for opportunity crudes are somewhat limited by our position as an inland refiner and being located far away from many of the crude pipelines. We are making changes in both the way we operate our units, as well as our capital investment, so that we can maintain our current slate with crudes of varying quality.
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Question 14: What reactions lead to acetone formation and how can they be mitigated? We have measured acetone concentrations between 100 and 1,200 ppm in the FCC butanes/butylenes stream.

We have very little data on this subject. We did find data on one virgin gas oil operation with 70 ppm to 110 ppm of acetone. If you are getting 1200 ppm, you probably have organic oxygen coming from some type of catalytically converted feedstock or recycle stream. We do not think you can have this level of acetone with pure virgin feedstock.
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