Q&A

(2013) Question 23: What are the operating strategies for C5/C6 isomerization units with current fuels regulations? Are units being run primarily for benzene saturation withchanges in operating parameters, feed sources, and treating being made to account for seasonal differences in gasoline pool RVP?

The answer is basically ‘yes.’ We are looking at isomerization units as benzene polishers for the light straight-run. Sometimes the light straight-run has too much benzene in it and a BenSat™ unit would be more appropriate for benzene conversion. The isomerization unit is an economic unit in the refinery.

(2013) Question 24: For refiners who have naphtha splitter columns, either upstream or downstream of a hydrotreater, how many of these towers experience overhead corrosion issues? Has oxygen played a role in any experienced corrosion? What solutions exist to mitigate the issues?

As a preface to my answer, I thought it important to define what we see as a splitter versus a stripper. To us, a naphtha splitter is a simple fractionator vessel. It takes naphtha and separates it into a light fraction that goes to gasoline blending and a bottom, heavier fraction that goes to catalytic reforming.

(2013) Question 25: What issues are encountered when introducing cracked naphthas into units that were not originally designed for the higher olefin content? What other contaminants should be considered when making this change in operation, e.g., silicon, nitrogen, and sulfur?

There are many potential issues. The single most obvious one is the heat released due to the olefins. You must make sure you can handle the heat release without coking up the reactor. You also have a higher risk of furnace fouling or coking in the furnace.

(2013) Question 26: How will the ISO 8217 Marine Fuel Oil Hydrogen Sulfide (H2S) specification (less than 2 ppm H2S in the liquid phase) affect refiners? Do any refiners plan to implement the standard, and what procedural or equipment changes are likely needed in order to meet the specification?

Simply put, refiners will be required to meet the ISO 8217 2 ppm H2S specification if they are going to sell fuel oil to customers who have requirements to meet this specification. ISO 8217 is a fuel specification, not a regulation. A regulation is enforced by some regulatory organization.

(2013) Question 27: What options are refiners considering addressing upcoming Tier 3 Fuel Standards [10 wppm (weight parts per billion) annual average sulfur in gasoline]?

Tier 3 fuel is lowering sulfur yet again in gasoline. The crude oil sulfurs have been coming down also with the tight oil, so some people have asked the question: Is processing more tight oil actually going to get us on-spec on Tier 3? The answer is no, not really. It is not going to have that significant of an impact on your gasoline sulfurs, obviously, without other processing.

(2013) Question 28: Is the changing quantity of pentanes and pentenes in refinery streams and tightening gasoline regulations leading to operators considering different processing strategies in order to maintain gasoline blend pool specifications? Comment on increased pentene alkylation, decreased pentane isomerization, or other disposition sources.

The pentenes, also called amylenes, can be fed to the alkylation unit and be alkylated. However, you make a lot of ASO (acid-soluble oil) and the yield is not that great; so, most people prefer not to do it. We do not alkylate our amylenes at the moment.

Question 49: In the past year, a sulfuric alkylation unit released a significant amount of sulfur dioxide to atmosphere when light hydrocarbon flowed from the reaction zone through the acid blowdown system and into the spent acid tank. What measures do you recommend for preventing this?

We would recommend ensuring that the acid knockout drum be sized large enough to allow the hydrocarbons to disengage in the drum.

Question 51: Reforming unit stabilizer column top trays and overhead condensers can experience fouling with ammonium chloride salts, which are commonly removed by online water washing of the column overhead. What practices do you employ to reduce the risk of rapid corrosion and the potential failure associated with this fouling and subsequent water washing procedure?

Ammonium chloride salts are a common problem in both naphtha reforming and naphtha hydrotreating units.

Question 60: How do you detect leaks in an isomerization unit's steam charge heater? Have you been able to detect a leak before a significant portion of the catalyst bed was deactivated?

The common problem in these units is deactivation of the catalyst by the ingress of water over the catalyst, because water actually deactivates the catalyst. This is a slide of a typical flow scheme for these units, and kind of shows you the conundrum of designing and operating these units.

Question 61: Have you found that you needed to install a methanator upstream of a chlorided catalyst isomerization unit to remove carbon monoxide (CO) from the feed? What is the source of the CO and how much of a difference has the addition of the methanator made to catalyst life? What is the expected payout for the cost of the methanator?

The problem now comes from the oxygen ingress coming in with makeup hydrogen, with the culprit typically being CO and CO2.

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