| American Fuel & Petrochemical Manufacturers

Question 51: What is the panel’s experience with recycle gas moisture analyzers?

Phillips 66 has had experience with the Ametek and Panametrics moisture analyzers. Weare talking about moisture in the reformer recycle hydrogen, so we are looking for 10 ppm to 50 ppm with varying success. I do not think we could say that one is a lot better than the other. The Ametek 5000 was designed for that application.

Question 50: How do you monitor the integrity of internals, and how do you determine when to replace reforming unit reactor center screens? What is the typical life of the center screens, and when are repairs considered excessive?

Typically, we have seen internals last between 15 and 20 years, if not longer. At any point, it becomes a value judgment between the number of repairs you have made, if any, and the potential outcome if the internals do fail.

Question 49: Does the panel have any experience using flexible thermocouples in the regeneration section of a moving-bed reforming unit? What considerations should be given to revamping units that do not have these installed?

Flexible thermocouples, as I understand, are now a part of the standard design for regenerators of moving-bed units. At a refinery in which I worked; we replaced the original slider thermocouples with multipoint thermocouples.

Question 48: Discuss recent advances in reforming catalyst technology. What performance improvements are being researched?

The most current catalysts on the market are multi-promoted using a number of different promoters beyond the base platinum-rhenium or platinum-tin. It is not a one-size-fits-all market, so there are tailored designs for different needs. For CCRs, the current drive is for improved yields. Units are often octane-long. The goal is now to maximize barrels as best as we can.

Question 47: How often do you replace your reformer catalyst? What is monitored, and what triggers the replacement? How has the increased spread between natural gas prices and liquid product prices impacted these decisions?

HollyFrontier operates five semi-regen reformers and two CCRs. There has not been a specific effort to replace catalyst in order to take advantage of the higher liquid product yield that is possible with newer catalyst. However, the spread between natural gas and liquids certainly impacts the decision when looking to upgrade. For two of the semi-regen units, the most recent catalyst replacements were installed after approximately 20 regen cycles, which included multiple dumping and screening events.

Question 46: Are refiners modifying the operating conditions in reforming units, for example, chloride on catalyst, in order to capture margin differences between natural gas, used as fuel, and liquid products?

I will start with a bit of review of some reactions, and then I will get into a couple of examples of what we have done at HollyFrontier. Of course, the downside to reforming is that the liquid product has less volume than the feed to the unit due to physical laws inherent to the chemical reactions. First, the high-octane product will have a higher density than the feed; and second, some portion of the feed will be cracked to LPGs and fuel gas in the process.

Question 45: What is the maximum allowable limit for the iron content of a reforming catalyst? Is this limit the same for semi-regenerative and continuously-regenerative catalysts?

We have seen that the maximum allowable iron on catalyst cannot be reduced to a simple number. Historically, about 3,000 wppm is the level at which we see yield start to suffer, but not every wppm of iron has the same impact on the unit. Iron deposited on the surface of the catalyst, usually from corrosion-related byproducts, tends to have less of an impact on the overall performance.

Question 44: How is coke on catalyst in fixed-bed and moving-bed reforming units tracked? How is this data used to adjust the reactor inlet temperatures in order to maintain constant product octane?

In our cyclic units, just based on the air consumption, we can measure the coke each time a reactor comes out for a regen. We are not grabbing samples. Our experience with the cyclics is that if you get up around 8% coke on catalyst, the unit will be pushed a little too hard. You will then need to think about backing it down on feed rate octane, finding a better-quality feed, or possibly increasing the hydrogen/oil ratio.

Question 43: In reforming units, what equipment could be susceptible to high temperature hydrogen attack (HTHA)? How are panelists approaching evaluation and replacement of equipment that could be susceptible to HTHA?

First, a little background: API 941 discusses high temperature hydrogen attack. At low temperatures, less than about 430°F, carbon steel has been used successfully up to 10,000 psi. But with elevated temperatures, the molecular hydrogen will dissociate into atomic hydrogen, which can readily enter and diffuse into the steel.

Question 42: What options are available to produce on-spec jet fuel from high total acid number (TAN) sources? What impacts these choices?

Regarding the conventional hydrotreating, I do not think high TAN would be an issue; but if you try to caustic-treat high TAN material, you will end up with what amounts to be the equivalent of lye soap. So anywhere you want oil and water separation to take place, the soap components may cause rag layers and carryover.

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