Q&A

(2015) Question 79: For units that have experienced elevated losses leading to coarse inventory, what options exist to improve catalyst properties during turnaround? Describe your experience with purchasing external or classifying spent catalyst.

We get fixed on how much 0-to-40 micron catalyst is in the inventory. You need 10% to run the unit well. And as Bob Flanders used to say, “Purgatory was trying to run a Model IV with less than 10% fines in it.” What I would suggest is certainly nothing smaller than 20 microns.

(2015) Question 80: What are your Best Practices to address increased levels of conventional and “new” metals (V, Ni, Fe, Ca, Cu etc.) in the FCC that come from tight oil processing in the refinery?

The first consideration should be removal or minimization of the contaminant metals upstream of the FCC. Since removing or limiting these contaminants may not be an option, other methods must be considered to address their negative impacts.

(2015) Question 81: Under what conditions is iron on FCC catalyst mobile, and how does this affect catalyst performance?

The first reports of FCC iron poisoning on a large-scale date from the 1990s. Iron was used in drilling liquids for oil recovery. Iron poisoning results in a loss of activity and an increase in slurry yield. The apparent bulk density of the catalyst decreases, which causes a drop in pressure differential over the standpipes and can lead to erratic catalyst circulation.

(2015) Question 82: What are typical and maximum targets for FCC unit main fractionator bottoms and wet gas scrubber water for weight percent solids? Also, what are typical for pounds per barrel (ppb) of catalyst losses to each and particle size distributions?

Typical total catalyst losses from both the reactor and regenerator side are somewhere around 0.05 to 0.1 pounds per barrel. A good assumption is that you have about a 50/50 split between your losses. From a maximum loss standpoint, you are looking at anywhere from 0.10 to 0.15 pounds per barrel for both the reactor and the regenerator.

(2015) Question 83: Can a slurry pump run at or below 1000 rpm (revolutions per minute)? If not, what is the lowest speed to minimize pump erosion?

The short answer is “Yes”, but it would not be a good FCC answer if I did not say the words, “It depends.” The actual effective service life depends on your solids loading in your slurry system, in both typical and upset conditions.

(2015) Question 84: What operating conditions and monitoring equipment have you been practicing avoiding sulfidation corrosion problems in main fractionator bottoms circuits? What guidelines have you established? How does sulfur type contribute to these guidelines?

Currently, we do not have the operators monitor or alter operating conditions for sulfidation and corrosion in the main column bottoms. We took a more traditional approach. We did a good process study throughout both FCC units with the total sulfur because that is what is represented on the McConomy curves, not the sulfur speciation.

(2015) Question 85: What operating practices or technology upgrades are you using to manage coking in the reactor overhead line at the main fractionator inlet?

Feedstock, catalyst, and reactor hardware all play a very major role in the vapor line coking. Coking of the reactor overhead line is a major concern, particularly when we are processing resids. Catalyst formulations designed for higher hydrogen transfer reactions, coupled with high aromatic feed, tend to produce higher boiling point PNAs (polynuclear aromatics), which have a tendency to condense and form coke in the vapor line.

(2015) Question 86: With more refiners upgrading to packing in the reactor stripper, what has been your experience with reliability? When do you consider removing packing for inspection during turnaround? How much of the packing does one spare?

We installed packing in our reactor stripper in 2006. So far, the only issue we have seen was in 2012. When we went into the reactor, we had refractory and coke debris from various areas of the reactor that had fallen onto the top of the packing and partially clogged and blocked a portion of the packing. We had already made the decision to remove all of the packing to evaluate whether there was any erosion with the new configuration (there was not), but we would have needed to remove at least the top two layers for cleaning anyway due to the debris.

(2015) Question 87: What has been your experience with gas and/or catalyst bypassing behind monolithic refractory linings? What are the possible approaches to prevent or correct this issue?

Most refractory problems are often due to poor installation and cyclic service. Hot spots are observed in the shell due to major refractory failure; but much more commonly, from the circulation behind the refractory. We have experienced gas and catalyst going behind the monolithic refractory lining. In such cases, hot gases are driven through the refractory by the head of the catalyst just above the entry point. The gas then exits from the dilute phase at the lower pressure zone. As the gas continues to travel through cracks and heats up the metal, the metal tries to expand while the refractory does not expand, which leads to refractory failure.

(2015) Question 88: Describe your approach to repair and improvement (i.e., materials, design, installation, and anchors) to areas that have seen repeated refractory failures.

Speaking of the improper refractory repair, especially in a hot-wall refractory with the coking service, low alloy base metal requires a 300°F preheat along with removal of all sulfides on the metal surface. If you do not do this, you will get weak and brittle welds that will crack easily because of their low weld strength. And therefore, your anchors will break off and your refractory will fail due to the coke growth behind the refractory.

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