Q&A

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.

(2012) Question 76: The check valve on the air blower discharge line is designed to protect the blower from hot catalyst that backs into it when the blower fails. What type of valve is used in this service, where is it located, and what is done to ensure that it closes properly?

UOP specifies two special check valves in the blower discharge line. The first special check valve is installed a minimum distance from the blower discharge downstream in the snort (or anti-surge) valve in a horizontal pipe run.

(2012) Question 77: For our emergency interlock system, we employ two-out-of-three voting systems for slide valve differential pressure transmitters. We use dedicated transmitter taps for each transmitter, but we get inconsistent readings. What can we do, regarding design and maintenance, to ensure that these transmitters read more consistently? What should we do if we are unable to achieve consistent readings?

To obtain a more consistent reading, plant personnel should examine three phases: the transmitter, its physical location, and its instrument gas system. As for the transmitter, the technician should analyze it to ensure that it is within the accuracy specified by the manufacturer.

(2012) Question 78: What inputs or trips are typically included in FCC flue gas expanders and CO (carbon monoxide) boilers' safety interlock systems? Are there any governing standards [(e.g., API and NFPA (National Fire Protection Association)] that apply?

I would like to address this question as two different parts, beginning with the flue gas expanders. BP has three flue gas expanders in its system. These expanders are all set up with slightly different configurations. We have one FCCU flue gas expander that is directly coupled to the main air blower.

Question 79: What tools are being used to monitor FCC performance? What are the key performance indicators and expectations?

These are two broad categories for the use of these indicators. The first category is capacity utilization and yield performance, which covers process performance, operating constraints, and optimal use of any inherent design margins.

(2012) Question 80: We are considering severe hydrotreating of our FCC feed. What yield shifts or unusual operating problems might we expect? What can be done to address these issues?

Processing Hydrotreated Feed: First of all, let’s define what ‘severely’ hydrotreated feed means. One unit in our system hydrotreats the feed down to 50 ppm sulfur and 50 ppm nitrogen, so you can see that processing that type of feedstock has tremendous yield benefits.

(2012) Question 81: Is there experience with continuous torch oil and/or air preheater firing; and if so, for what reasons? What are the demonstrated effects from doing either of these processes?

We do not have much experience with continuous torch oil firing. We do have one unit that fires torch oil if the bed temperature drops below 1250ºF.

(2012) Question 82: Do you have any experience with the recycle of C4/C5 streams from the FCC gas plant back to the FCC? If so, what was your motivation? What is the system configuration, and what are the key operating parameters?

We have some experience recycling BBs (butane-butylenes) from the gas plant back to the FCC reactor, and even some C5s. I will start by saying that this is a very unusual operation.

(2012) Question 83: What is the typical flashpoint for your slurry oil product? Can a flashpoint 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?

I will start by saying that everyone should reference Question 84 of the 2011 NPRA Q&A because this question is an exact replica of what was answered by BP and Western Refining last year.

(2012) Question 84: What measures can be taken to reduce the residence time in the FCC main fractionator to offset slurry circuit fouling? What basis is used to determine the residence time in the main fractionator bottoms?

I would like to start with a little background on bottoms coke to present some clarity on the basis for my answer to this question. Bottoms coke sources could come from multiple places. But to address the question with respect to residence time, our impression was that we are mostly looking at the thermal cracking and decomposition reactions in the main fractionator bottoms as opposed to asphaltene precipitation or reactor transfer line coke generation and carryover.

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