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.

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.

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.

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.

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.

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,

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.

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.

GRUBB (Chevron USA, Inc.) I consulted our corporate experts for this, Shingou Lou and Dave Kohler. We built one in Pascagoula and their basic response was that there’s really no reason to expect any more instability problems than you would have with normal olefins. And as with the other olefins, if you let them go unchecked, they could lead to an insoluble gum residue. These can be mitigated effectively with some antioxidants—the phenylenediamine-hindered phenol. They do recommend that you inject them very close to the source unit. Like I said, Pascagoula converted an MTBE plant and we had no instability issues at our plant. Corporate-wide, we actually have experience with two ion exchange resin-type catalyst units, two solid phosphoric acids distributed on solid support-type catalyst units, and we have experience with Dimersol-type units.

KAISER (Delek Refining Ltd.) Again, just to re-emphasize, I’m not currently on an HF unit so part of this response will rely on some former colleagues of mine. I would not make a blanket recommendation to change the material specification for carbon steel in HF alkylation units. To me, the risk is too great. I understand that there are certain times when things are tight and you might need immediate material delivery and there’s no other option, but I would not make a blanket relaxation in the material specifications.