Q&A

(2012) Question 96: What is the CO boiler start-up and shutdown sequence with respect to the FCCU start-up and shutdown timing? What are the reasons for this sequence?

As I mentioned briefly in an earlier question, most of our FCCs with CO boilers start-up with the CO boilers bypassed. If we run partial-burn on any of these FCCs, we tend to start-up in full-burn at reduced rates. Once the feed is in the unit and considered stable, most sites will cut into their CO boiler with the process flow.

(2012) Question 97: What equipment do you employ to help eliminate ESP hopper and downcomer plugging with catalyst fines? What additional operating practices are used? What type of level detectors are in use on the ESP hoppers and/or catalyst storage silos? Are there any new level detection technologies that could be applied, perhaps from coke drum measurement detectors?

Our main problem with the ESP is fines accumulation in both the ESP hoppers and the transfer line from the hoppers to the fine's storage bin. We have incorporated some design improvements that have helped us minimize, but not completely eliminate, the main problems of condensation in the system and plugging.

(2012) Question 98: What is your experience with the use of ammonia or steam in the FCC flue gas line in order to improve the operation of the ESP? Please comment on system configuration and operational issues

We have extensive experience with the use of ammonia in the FCC flue gas line in order to improve the conductivity of the particles and improve the operation of the ESP. We inject ammonia at the target level of 10 parts per million or less.

(2012) Question 99: Have refineries experienced an increase in particulate emissions in the regenerator flue gas caused by oxygen enrichment of air to the regenerator?

We have quite a few refineries that use oxygen enrichment. One of them uses it in very high concentration. None of the sites – and I spoke with them specifically about this – say that they have seen an increase in particulate emissions as a result of increasing their oxygen enrichment.

(2013) Question 29: What are the industry practices to take samples around high-pressure equipment which contain light hydrocarbon and H2S? How do you ensure the samples are handled safely and representative of sample stream?

Our Corpus Christi and Pine Bend refineries had standardized on Texas Sampling Incorporated samplers. They provide a variety of closed loop captured sample systems. We have a Sampler Selection Procedure Flowchart that helps us walk through ‘yes’ or ‘no’ decisions considering high RVP (Reid vapor pressure) material, high-pressure material, high temperature material, high H2S (hydrogen sulfide) options, and plugging potential.

(2013) Question 30: What are your design practices for reactor skin thermocouple requirements in a hydrotreater and a hydrocracker for startups and safe operation?

Our minimal requirement for a hydrotreater is three skin thermocouples at the top and bottom heads of the reactors and a full skin thermocouple at the bottom shell of the reactor just about at the tangent line. The option now is a full skin thermocouple at the top of the shell and the middle of the shell.

(2013) Question 31: What is the threshold concentration of arsenic and phosphorus requiring a dedicated trap system? How are the arsenic and phosphorus trap systems specified,and what are the controlling mechanisms?

Arsenic is a big concern because it is a permanent poison that causes fairly significant activity. We generally see around a 60° Floss per weight percent pickup; so, you will want to pay attention to it. As a side note, it is also common in most fractions of hydrotreating: so anything from naphtha to heavy gas oil.

(2013) Question 32: What is a typical range of HDM (hydrodemetallization; metals removal) in a gas oil hydrotreater? Can HDM decline rapidly when metals in the feed become excessive relative to catalyst system design? Is there a point when metals in the feed are so high that they “overwhelm” the demet (demetallization) and main bed catalyst, resulting in lower percent of HDM?

Nickel and vanadium contamination generally come in heavy gas oils and resid hydrotreating. It is obviously not very common in diesels and light feeds. We see that it is about a 5°F to 9°F loss per weight percent combined pickup. The reason you will want to pay attention to these metals is because of their ability to actually diffuse onto the catalyst, so you will need a space to deposit them.

(2013) Question 33: What is the philosophy or criteria for optimizing catalyst bed grading material to prevent high reactor pressure drop from feed containing significant amounts of Fe (iron)?

Certainly, identifying the sources of the iron coming in – whether organic, iron oxides, iron sulfides, or just scale from tanks – is very critical to understanding your best strategy for mitigating pressure drop. Ultimately, when you form iron sulfide, it creates deposits on the bed and coke deposition, and certainly leads to reduced catalyst life.

(2013) Question 34: When processing cracked naphtha, what is done to ensure that polymerization of the diolefins/olefins will not result in pressure drop problems in a reactor or upstream equipment?

Again, we are trying to prevent the polymerization of the olefin/diolefin. The primary concern is trying to prevent contact with oxygen because that will ultimately lead to gum formation. So, the preference would be, if possible, to feed this hot to all the downstream units and avoid intermediate storage.

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