| American Fuel & Petrochemical Manufacturers

Question 16: A number of refiners are adding a chloride dispersant to address FCC main fractionator overhead system plugging issues. What is your experience with these products and have you had issues with downstream gasoline product quality?

Processing of increased amounts of imported FCC feed, both gasoline and reduced crude, results in increased chloride salts in the main fractionator, which is usually a result of sea water contamination of transfers. Ammonium chloride salt dispersant is a chemical, which can be used to move or disperse ammonium chloride salts to prevent pluggage of the FCC main fractionator.

Question 15: What variables influence gasoline aromatics? In particular, please address feed properties, catalyst, and FCC operating conditions.

Feed properties play an important role, namely the amount of one- and two-ring aromatics in the feed. Single-ring aromatics pretty much go straight to gasoline. Many single-ring aromatics in gasoline, however, are formed via reactions; either via cyclization or the cracking of partially saturated multi-ring compounds.

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.

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.

Question 12: For FCC units with closed riser termination device (RTD)/cyclone systems, do you operate with the primary separator sealed or unsealed in the stripper bed? What differences in performance do you see between these modes? Which do you prefer?

The answer to this question depends on the specific RTD technology.

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.

Question 10: What is your recent experience regarding the maximum level of equilibrium catalyst metals (Ni, V, Na, Fe, Ca) in FCC units processing residual feedstocks? Have there been any recent improvements in vanadium passivation technologies? At nickel levels approaching 10,000 ppm, have you experienced increased catalyst deactivation as evidenced by lower equilibrium zeolite surface area?

Here we see data regarding one of our FCCUs that operates at e-cat nickel levels exceeding 10,000 ppm. We observe that the MAT generally remains within the same range until high e-cat nickel concentrations are approached.

Question 9: Are there specific lab studies or commercial examples regarding the effect of regenerator temperature on catalyst deactivation and particle integrity, specifically attrition properties, apparent bulk density, and morphology?

There is a very definite correlation between activity degradation and regenerative temperature. Some catalysts are more susceptible to thermal deactivation depending on the technology and the poor architecture used.

Question 8: What level of PM2.5 particulate removal do you expect (or have achieved) with flue gas fines separation and removal equipment such as third-stage separators, fourth-stage separators, electrostatic precipitators, or wet gas scrubbers?

We have not benchmarked particulate removal technologies within our system for PM 2.5 removal. This data is difficult to obtain because many stack tests do not analyze the captured particulate matter for particle size distribution or PSD.

Question 7: Is your company either considering, or actually implementing, FCC projects that include reduced CO2 emissions (greenhouse gas reduction-GHGR) as an offset/credit?

We do not have any current FCC projects that plan on utilizing some form of CO2 offset or credit in the emissions analysis. ConocoPhillips has performed a limited modeling study to evaluate the effect of operational changes on CO2 emissions from the FCC. Also, the study indicated that there is very little you can do to reduce overall emissions without also overall significantly reducing unit throughput or conversion.