Damages to the top section of the coker trays could be due to process-related reasons or mechanical or operational issues. One process-related reason is salt deposition. Usually, the salt is ammonium chloride. It is water-soluble, corrosive, and rapidly deposits at the right conditions, leading to severe loss of tray capacity and efficiency.

Our particular configuration for tight oil processing allows us to operate one of our cats with ARC (atmospheric reduced crude) without any impact to our coker operation. We typically have sufficient feed, but the obvious answer might be to purchase additional number 6 fuel oil or vacuum tower bottoms for operation.

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.

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.

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.

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.

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.

We have experience with two types of organic tower fouling. The first was an organic fouling in the top portion of the tower due to rerunning cracked slop oil, coker naphtha, and kerosene material. Typically, we do not want to do that. Since then, we have stopped processing those materials or limited the amount that we are rerunning so it does not happen anymore.

Our belief is that a proper design includes a good waterwash system and less expensive metallurgy. Our tower tops are typically carbon steel with Monel overlay.

At CITGO, we utilize both daily monitoring tools and weekly programs to rank the heaters based on performance and missed opportunity. Optimization targets get set based upon best efficiency points, and the consoles are expected to be at these optimization points.