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(2008) Question 80: Where in the isomerization reactor catalyst bed does the hydrogenation of benzene (exothermic) occur? How does this affect the other isomerization reactions? What concentration of benzene in the isomerization feed is acceptable?

ZMICH (UOP LLC) This question refers to or asks about benzene hydrogenation and how it affects to isomerization reactions, maximum levels in the feed, and where does it happen in the reactors. So what I thought we would do is start out with what am I talking about: benzene saturation.
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(2008) Question 81: Has the optimum feed for light naphtha isomerization units changed given that: 1) ethanol blending reduces the octane value of other blendstocks; 2) the demand for premium gasoline is down; and, 3) ethanol blending increases RVP compliance costs? Are you removing pentane from the isomerization unit feed stream or shutting down the unit? Or, are the units still valuable for isomerizing normal hexane and saturating benzene?

KAISER (Delek Refining Ltd.) The question is very well phrased in that the introduction of ethanol into the blend pool does tend to reduce the need to run the isomerization unit in that ethanol is a very high RVP blend component, and it has enough octane to be able to possibly offset the need for the octane boost that you’re getting out of your isomerization unit. So when a refiner wants to introduce the ethanol into their blend pool, there are three likely scenarios that they’ll go through in their unit operations. The first is obviously shut the isomerization unit down.
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(2008) Question 82: In light of coming benzene regulations, are you using (or planning to use) the isomerization unit for benzene conversion? How does this affect isomerization catalyst performance and unit operation? How does this affect the gasoline pool? How does benzene saturation in an isomerization unit compare to a dedicated benzene saturation reactor/catalyst?

ZMICH (UOP LLC) This question relates very well with Question #80 that we discussed a few minutes ago, and what I’d like to do is touch upon some of the key points that we mentioned there. So Item #1 on the slide relates to the naphtha isomerization units being flexible in their ability to handle benzene. Typically, 3% benzene in the feed and in a range of 0 vol% to 5 vol% is normal. For item #2, as benzene increases, the reactor ΔT increase because of the heat of reaction, decreasing the research octane number or the PIN. The higher temperature means lower isomerization or lower iso ratio. Also, as benzene increases, it poisons more of the catalyst in the reactor, which effectively is increasing the space velocity across the reactor,
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(2008) Question 83: Since Sulfolane-based aromatic recovery units are experiencing corrosion-related problems, are there alternative solvents available? What are the advantages and disadvantages of these alternatives?

METKA (Sunoco, Inc.) We operate four solvent extraction units. The literature reports that there are alternative solvents available that have more capacity and are more selective than the traditional solvents. The degradation products, however, can still be corrosive. The use of any of these new solvents should be carefully reviewed and evaluated. Comprehensive review of your existing unit design and how it relates to a new solvent is essential. Our experience is that the corrosion tendency and acidity of the tradition solvents can be controlled if the solvent is properly monitored and maintained.
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(2008) Question 84: What is your experience with cleaning multi-upcoming trays in aromatics extraction service? What cleaning methods are most effective?

QUINTANA (Valero Energy Corporation) While we do have some multiple upcomer trays installed in one of our extraction units. We haven’t really had to clean them as yet, but we have used various methods to clean the conventional rain deck extractor trays in our other units. As such, we do believe that those methods should be similarly successful with MU trays. Generally, we first would steam out the extractor from the bottom and then follow that up with a hot condensate wash from the top down. That tends to loosen all the bulk foulants, breaking them into smaller pieces, washing them down to the bottom of the extractor and flushing them out.
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(2008) Question 85: Olefins that are formed in the catalytic reforming process must be removed or converted when the reformate is processed in an aromatics extraction unit. Historically, what unit operations have been used to remove/convert the olefins in the reformate? Are there any good alternatives to clay treating? How do the alternatives compare to clay treating with respect to capital cost, maintenance, operating cost, environmental impact, and effectiveness of olefin removal?

QUINTANA (Valero Energy Corporation) The olefin content of the reformate is determined by thermodynamics at the last reforming reactor. With higher severity, whether it’s from a leaner feed, lower pressure, lower hydrogen-to-hydrocarbon ratio or higher octane, you will produce higher olefin content in the reformate. Those olefins are going to be distributed more towards the lighter end; that is, the C6 fraction has higher olefins than the C7 fraction, which is higher than the C8 fraction, and so on.
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(2008) Question 86: The reformer’s feed properties can be affected when the refinery is maximizing refinery diesel yield. How do these changes to reformer feed affect performance with respect to C5+ yield, hydrogen production, cycle length, and economics?

NEWTON (Roddey Engineering Services, Inc.) As everyone knows, we’re not here to discuss how to make more gasoline; we’re here at the conference to learn how to make more diesel, so I just hope you people in here... But whenever you start to talk about maximizing diesel yield from most refineries, what you’re going to talk about is shifting the heavy end of the reformer feed to the diesel stream and so you lower your endpoint to the reformer.
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(2008) Question 87: Iron contamination of CCR, cyclic, and semi-regen reformer catalyst is a common problem. What level of iron concentration typically justifies catalyst replacement due to poor catalyst performance?

METKA (Sunoco, Inc.) Typically, iron levels up to approximately 12,000 ppm can be tolerated before a change-out is required. Iron is a support modifier that can affect both the metal and acid sites. There is more of an impact on the acid sites, and iron can impede chloride pick-up and trap sulfur on the catalyst. Iron typically impacts the first reactor in a fixed-bed unit and is primarily a result of upstream corrosion in the naphtha hydrotreater.
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(2008) Question 88: What is your experience with feed-side fouling on combined feed/effluent (CFE) exchangers? What is the foulant? How often do you clean them and what cleaning techniques do you use? On Texas Towers (vertical shell & tube exchangers), how do you extract the bundle from the shell if it gets stuck?

NEWTON (Roddey Engineering Services, Inc. Engineering) I’m just going to deal with Roddey Engineering’s experience. I know some people on the panel have different experiences. But as far as feed effluent exchangers go, and especially Texas Towers, we have seen significant fouling on all that we’ve dealt with. Pretty much every refinery that has one, they do not clean the tower.
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(2008) Question 89: What are the typical problem areas for CCR catalyst circulation loops? What are the most reliable valve types? How frequently do you conduct fines surveys and what is a reasonable range for fines make?

GRUBB (Chevron U.S.A., Inc.) My experience here is with the design of a new unit in Pascagoula. So we went to the other CCRs within the Chevron system and asked this question already on how to increase our reliability with that project. This is a roundabout answer arranged from all the different operating ones. On the valve types, I’ll just state that all of Chevron’s experience is with the UOP designs and what we do is we specify soft seat on the “V” notch ball valve wherever the catalyst flow must be stopped. We use a double-seated plug and globe “G” valves on the vents and spring loaded “B” ball valves for the gas tight seal on the catalyst transfer line.
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