Q&A

(2015) Question 7: Recognizing that onstream factor is an important component of margin capture, what are the common areas of improvement for each of the gasoline processing units to reduce downtime or increase turnaround interval?

Turnaround time intervals approaching 60 months are becoming more frequent as processes and procedures improve over time. The incentive to extend the turnaround cycle beyond 60 months does nothing more than prolong turnaround times.

(2015) Question 8: How will the recently announced EPA regulations on emissions impact your refinery operation and specific technologies [FCC, hydroprocessing, coking, CDU/VDU (crude distillation unit/vacuum distillation unit), reforming, etc.]?

Refinery risk and technology rules were adopted last week on September 29th. They are expected to have a significant impact on the refining industry. The rules require additional control and monitoring of the emissions from the refineries and the emission reporting that is available to the public and other neighboring communities.

(2015) Question 9: Is there a limit on the amount of time acid can remain stagnant in the reaction section of the alkylation unit? What adverse effects may occur if this limit is exceeded? What issues could arise on a restart from a stagnant-acid condition?

We have found that if we can bring the unit down in a controlled fashion – specifically, if we can clean up the acid by circulating isobutane for a few hours and clear the acid of any reactants, then we can let it sit there for 24 to 36 hours, maybe even 48 hours, without any kind of issue.

(2015) Question 10: Where is carbonyl sulfide found in alkylation units? What effects can it have on the unit, and what are the prevalent management strategies?

Again, I am focusing mostly on sulfuric acid units because that is where I have experience. Carbonyl sulfide (COS) is a noncombustible gas that will follow propane and propylene. So, if you are running all of your FCC olefins, then you will get it into the reactor and into the refrigeration section.

(2015) Question 11: What operating variables lead to increases in organic fluorides in LPG product streams in a hydrofluoric (HF) acid alkylation unit? What operating variables lead to increases in organic sulfates in sulfuric acid alkylation units and where do these compounds concentrate?

The HF alkylation reaction is a two-step process. The first step of the reaction goes rather quickly, and anything that slows a reaction down will allow a stable organic fluoride to form. So, the factors that increase organic fluoride formation are temperature at I/O ratio and usually acid strength.

(2015) Question 12: What are your Best Practices for maintaining good reliability of pH analyzers in sulfuric acid alkylation service?

In sulfuric acid alkylation plants, alkaline water is used to neutralize acidic components that are present in the hydrocarbon effluent. To achieve the neutralization, the alkaline water pH is typically maintained between 11 and 12, and the temperature controlled between 120°F and 160°F.

(2015) Question 13: Is it a common or recommended practice for you to changeout all HF alkylation unit pump seals during turnarounds? What strategies do you employ to improve pump seal life in these services?

We have seen considerable interest in pressure, temperature, level, and flow instrumentation to monitor auxiliary seal flush systems as specified in API Standard 682, as well as the special flush piping plans for hydrofluoric acid services as specified by the process licensor.

(2015) Question 14: What do you consider when evaluating options for sulfuric acid regeneration? Comment on owned and operated facilities, onsite third-party, and offsite third-party operations.

I think the first consideration is: Do you have access to a reliable supplier? Your alky plan needs a supplier, either onsite or a third party, who meets your requirements in terms of on-time delivery and quality. Refineries do not want to have a slowdown or shutdown due to delivery issues of acid to the alky plant.

(2015) Question 15: What are your options for processing of disulfide oil from an extractive mercaptan removal unit? How will this oil affect a naphtha hydrotreater?

Historically, disulfide oils would be blended back into the gasoline pool; but in the days of Tier 2 gasoline, this option is no longer available. The question of how to dispose of disulfide oils is one that comes up frequently within the company. Options that are often discussed are whether or not disulfide oils can be reprocessed in the cat cracker, the crude unit, or the coker.

(2015) Question 16: Do you plan to utilize a mercaptan removal unit in conjunction with a gasoline selective hydrotreater to meet Tier 3 gasoline sulfur requirements?

To meet Tier 3 10 ppm sulfur in the gasoline pool, FCC naphtha will need to be treated to 10 to 35 ppm. The target FCC naphtha sulfur level is based on the sum of all the other sulfur species in the pool, as well as the percent of FCC naphtha in the pool, as indicated in the plot.

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