Q&A

(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.

(2015) Question 17: What considerations should you make when contemplating changing catalyst supplier from the original unit licensor?

Changing catalyst suppliers is not an uncommon practice. It is done successfully in many different locations. Typically, cost and yield improvements are the most influential factors. However, there are some other key considerations before making the change.

(2015) Question 18: Due to lower product octane requirements, has your strategy for dumping and screening fixed-bed reforming catalyst changed from the standard recommendation of three years or three in-situ regenerations?

As with any catalyst, the deactivation rate is a function of processing similarity; and consequently, if the unit is targeting lower octane values, regeneration requirement can become less frequent. It is really up to the refiner to make the decision as to whether or not to let the cycle extend out longer because of the lower production of the coke or to regenerate more proactively on an annual basis to ensure that the yield losses are maintained at a minimum.

(2015) Question 19: What is the maximum recommended nitrogen content of reformer feed for continuously regenerated units? What is its impact on chloride consumption and ammonium chloride generation?

The typical licensor guideline is 0.5 ppm maximum nitrogen in the feed. When nitrogen contacts the catalyst in the reforming unit, it essentially strips chloride from the catalyst. The reduced chloride on catalyst results in reduced catalyst activity.

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