| American Fuel & Petrochemical Manufacturers

Question 12: Gasoline blending is becoming more difficult due to the increases in quality specifications; lower sulfur and benzene, for example. What changes are being made to blending facilities and operations to accommodate these changes? Please discuss tankage allocations, working inventories, online analyzer needs, procedural changes, in-line blending, etc.

Blending has indeed become more difficult with the lower product specifications, but our blend methods have only experienced small evolutionary changes in response to the new specs. Most of the changes involved recertification of established methods to demonstrate compliance with the new standards.

Question 11: What changes have refiners made in metallurgy from design specifications? What recommendations have the licensors incorporated into new specifications based on experience and user feedback? Comment on both HF and sulfuric acid alkylation.

The short answer is that there are not very many deviations from the design metallurgy in HF units. Any changes that have been made are based on observed corrosion rates within the unit.

Question 10: What is the industry experience with continuous online acid strength analyzers in HF and sulfuric acid services? Please comment on accuracy and reliability.

Again, I will address the HF units. UOP is aware of two vendors who are marketing online analyzers for percent HF and percent water. The experience of their customers has been generally positive. These analyzers give continuous readings, so you can detect issues much faster.

Question 9: What are the latest strategies for feed dispersion and mixing in HF and sulfuric acid alkylation? How does mixing affect alkylate endpoint? Does better mixing allow for operations at reduced I/O ratios via increased olefin charge rate or operating against isobutane constraints?

I am going to address the HF units again. For the first question, it is more of an issue of, “If it ain’t broke,” we are not going to fix it. The types of mixers are simple in the HF unit. An orifice-type mixer is used for mixing the olefin and the isobutane recycle, and then a spray nozzle is used to mix the isobutane in the olefin into the acid.

Question 8: What is the industry experience with de-isobutanizer (DIB) feed pre-heatexchanger or reboiler fouling? What are the typical causes of the fouling? How do you mitigate this problem? Comment on both HF and sulfuric technologies.

I am going to talk about HF alkylation units only. The feed pre-heaters for the isostripper or main fractionator have experienced corrosion and fouling. There are several possible causes. One is getting the metallurgy, which is typically carbon steel, too hot. If you go over 160°F in the presence of HF, it gets very corrosive; so, you can lose metal that way.

Question 7: Given challenges in gasoline Reid vapor pressure (RVP), benzene, low-carbon fuels, and other requirements, are refiners considering expansion or other changes to make more alkylate? Has increased catalytic polymerization become a consideration?

UOP has not observed a big uptake in project activity related to this issue. However, we have observed more interest in revamping existing alkylation units rather than new projects.

Question 6: Has isomerization become more important as feedstocks have become more paraffinic with the increased processing of ‘tight oil’ feedstocks? Do ‘tight oil’ feedstocks contain more benzene?

For this question, I looked in our assay database at the light straight-runs since we spoke a little about isomerization then. Really, if you think about benchmark crudes like WTI (West Texas Intermediate) and WTS (West Texas Sour), and if you consider Bakken and some of the Eagle Ford crudes as tight oil crudes, then the only one that really pops out as being meaningfully different is the Eagle Ford Light or the Eagle Ford condensate that some people are running.

Question 5: Reforming of feedstocks from ‘tight oil’ crudes offers unique challenges such as low naphthene and aromatic (N+A) content, lighter feed, and differences in coke yield.What are refiners doing to address these challenges and generate opportunities for these new crudes?

From a project standpoint, there have been inquiries related to tight oil and proposals generated, but not a significant number of actual projects realized for revamping units. It appears that most refiners are able to accommodate the tight oil in their existing units. Some of this accommodation has to do with the naphtha area capacity issues in the U.S. of which I am sure everyone is aware.

Question 4: Is there any experience producing on-specification jet fuel without any sulfur/mercaptan treating, including any form of caustic, from feedstocks produced from ‘tight’ formations? What other jet specifications are adversely impacted by the changed feedstock?

The main idea here is that there is no real change to the way you make jet fuel based on tight oil. There may be slight changes to the freeze point due to the paraffinicity of the tight oil, but that is actually just dependent on the tight oil itself. If that is the case, really all that is required is a cutpoint adjustment in the crude unit to get on-spec on the freeze.

Question 3: What drives the decision to load presulfided, presulfurized, or oxidized catalyst in naphtha hydrotreaters? What are the different safety considerations for each case?

I would like to begin my responses by grounding us in some definitions. Pre-sulfided catalyst is the catalyst that is delivered with an active metal sulfide site. Pre-sulfurized catalyst is catalyst in the oxide form but which then has added to it an organic sulfur compound. The metal sulfide sites are then formed in-situ during the startup process. Finally, sulfiding is the process of injecting a sulfur compound into the reactor for in-situ sulfiding after the catalyst is loaded.

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