| American Fuel & Petrochemical Manufacturers

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.

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.

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.

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.

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 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.

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.

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.

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.

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.

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