Q&A

(2011) Question 84: What is the typical flash point for your slurry oil product? Can a flash point of 200 F or higher be achieved with steam stripping the main fractionator bottoms? What are your storage temperature guidelines? What lower explosion limit (LEL) and H2S levels are found in the tank vapor space?

This topic of slurry oil flash point and control has been a recent discussion topic at our FCC units. Collective inputs indicate the range of flash points temperatures are from 140degF to 220degF.

(2011) Question 85: How often do you clean the FCC slurry exchangers?

For us, as I'm sure for it is for others, minimizing FCC slurry exchanger cleaning has been a continuous improvement effort for quite some time. As a result we have implemented best practices in the areas of slurry circuit and fractionator operations and design. Through these efforts we have some units that only need to clean during cycle ending turnarounds.

(2011) Question 86: What is the panel experience with polythionic acid stress corrosion cracking of the regenerator and/or flue gas system? How rapidly can it occur? What preventative measures can be practiced? What might cause the corrosion to occur soon after equipment commissioning?

Due to high temperatures and limited moisture, polythionic acid stress corrosion cracking (PASCC) in FCC regenerators and flue gas systems are relatively rare. A specific set of criteria must exist before PASCC of austenitic stainless steel is possible. First, sulfide scale, liquid water and oxygen must be present.

(2011) Question 87: Some sources advise that the main column inlet flange should not be insulated because the bolts will reach operating temperature and lose strength. Thermal cycling compounds the problem. We did not insulate this flange and found coking in this region. How do you minimize heat loss and coking but still maintain bolt strength?

UOP’s standard specification for piping states “Flanges, including valve body to bonnet flanges, on insulated process lines or equipment with an operating temperature over 800°F (425°C) shall not be insulated”. The reason for this is so that the bolts do not lose strength or expand too much at high temperature, potentially causing a flange leak.

(2011) Question 88: Have you employed chemical additives to keep FCC expanders and other FCC flue gas equipment free of catalyst deposits? Were they successful?

Several years ago, one of our refineries attempted to use a chemical to remove fines from the flue gas expander. The injection system was not optimal and it actually increased fouling so we would not recommend this method.

(2011) Question 89: Are there advances in cyclone lining material or cyclone designs to make them more erosion resistant allowing higher cyclone velocity or longer run lengths?

We limit the regenerator cyclone inlet velocity to 75 fps to make 4-5 year runs between turnarounds. Reactor cyclone inlet velocity limit is 80 fps if there is a rider termination device that reduces the catalyst loading to the cyclones.

(2011) Question 90: Do you have experience with slide/plug valve independent movements without any controller action?

There are 5 categories of initial causes which may lead to erratic slide valve movements in auto mode. These are oil contamination, servo valve amplifier tuning, part failure, mechanical linkages, and electrical connections. Oil contamination is the initial cause a vast majority of the time.

(2011) Question 91: What methods other than jack hammering, water jetting and low charge explosives have you used to remove coke during turnarounds? What are the advantages and the risks for these methods?

Jack hammering is the most popular method for coke removal as it is effective and is the lowest risk to equipment. As stated early, jack hammering can be used effectively around refractory as long as the refractory has stainless steel needles. The chipping hammer will through sparks when the chipping hammer cuts through coke and starts to hit refractory.

(2011) Question 92: Aside from erosion failures, what is your experience with newly installed lining failures in vibration-cast cold wall risers and standpipes? What caused the failures? What can be done to prevent or mitigate the failures?

Valero has experienced this at one of our revamped FCC units on very long regenerated catalyst standpipe, near the top of the reactor riser in two other units. There are numerous hot spots that can be quenched with steam lances.

(2011) Question 93: We are aware of at least one refiner who replaces the regenerator head, including cyclones, at every turnaround to eliminate the time required for inspection and repair. What are the key factors you consider when assessing the economics of replacing the regenerator and/or reactor head(s) versus the traditional procedure of internal inspection and repair? How does the size of the regenerator and/or reactor play into the decision?

Valero has experience with replacing the regenerator cyclones by cutting off the regenerator head and replacing with a new head and cyclones when the cyclones are at end of life.

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