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(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.
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(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.
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(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.
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(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.
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(2013) Question 66: What strategies should be considered to adjust for phosphorous in crude oil to protect downstream catalyst and processing units?

Extensive work was done with Western Canadian refineries in the late 2000s to investigate and solve this problem, including adjusting desalter pH to extract phosphorous in the desalter brine, adding a phosphorous removal chemistry, changing the trays in the crude tower to reduce fouling susceptibility, solvent-washing the deposit to avoid long cleanouts and shutdowns, and adjusting process temperatures.
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(2013) Question 67: When heat input is limited at the vacuum heater, what are the issues with bypassing crude tower over-flash around this heater?

For this answer, I am going to define crude tower over-flash as liquid collected on a collector tray above the flash zone at the atmospheric crude column. This may be either a total collector tray or some form of active tray. This liquid contains a mixture of entrainment from the flash zone and distillate from the wash section. The normal disposition is to send the liquid inside the tower down to the stripping section.
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(2013) Question 68: For those refiners seeing an increase in vacuum overhead chloride concentration at constant desalted crude salt content, what are the consequences and how can they be controlled?

First, verify the chlorides found in the hot well water. Could the chlorides be from leaks from the vacuum system condenser cooling water? A hardness test will quickly identify water system leaks. Essentially, getting a high chloride concentration in the vacuum overhead at a constant salt content in the desalted crude implies either a change in the chloride type or in the operating conditions leading to more chloride hydrolysis.
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(2013) Question 69: What are some of the advantages and challenges in processing FCC slurry in a vacuum tower along with conventional atmospheric residue streams?

If you feed FCC slurry to the vacuum unit, the major benefit is recovery of diesel range material. High temperature limits in the bottom of the heavy cycle oil slurry fractionation system limit diesel recovery from slurry. Typical limits in this section in the FCC are 720°F, or 382°C; above that, coking starts to be a major issue.
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(2013) Question 70: What are the key areas to target when contemplating crude unit modifications to enable effective tight oil processing? In addition to these modifications, what other problem areas become evident once the actual processing begins?

We run tight oil in six of our seven plants, and it is mixed in the basket of the other 10 to 20 crudes normally processed. Tight oils are not the predominant crude in most places, so we have not needed many modifications. In two instances, we did have tray fouling from drilling mud; so, we installed low fouling trays.
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