Q&A

(2014) Question 21: Have you had experience with buildup on pump seals in stabilizer or debutanizer reflux pumps that process material that potentially contains chloride salts? In what circumstances do you use salt dispersants and could they mitigate or aggravate this phenomenon?

Have you had experience with buildup on pump seals in stabilizer or debutanizer reflux pumps that process material that potentially contains chloride salts? In what circumstances do you use salt dispersants, and could they mitigate or aggravate this phenomenon?

(2014) Question 22: What is your method to clean a "Texas Tower" type of combined feed/effluent exchanger? Comment on the differences between cleaning in-place, extraction and reinsertion, and online cleaning.

Pulling the VCFE tube bundle can be very difficult. Removing and re-installing the bellows is also a difficult task. Care should be taken not to damage the exchanger when pulling or installing the tube bundle. In addition, setting the bundle in the horizontal will, in most instances, cause damage such as tube to tube sheet leaks.

(2014) Question 23: What are the sources of platinum loss in precious metals catalysts? What role can your refinery engineers play in minimizing this loss?

Typical operating conditions in a reformer do not result in platinum volitization. However, it is possible for Platinum to become volatile and come off the catalyst at very high temperatures. One place this can occur is in the Chlorination zone of the CCR Regeneration Tower, where slipping coked catalyst into an oxygen rich atmosphere can result in very high temperatures.

(2014) Question 24: What is the maximum oxygen content you allow for the platinum redistribution step in a fixed bed reformer? What sets the maximum oxygen concentration?

Directionally the higher O2 level is better for metal dispersion during oxidization. UOP recommends aminimum of 5% with typical maximum O2 content of 8-10 mol% based on the seal oil combustion limits. Dry seals or nitrogen purge seals allow higher O2 content without explosive conditions.

(2014) Question 25: What factors contribute to your decision to place the regeneration section of a CCR in standby mode when the unit is operating in a low-coke mode? Discuss the advantages and disadvantages of the different standby modes (black-catalyst circulation, hot-shutdown, cold-shutdown, etc.).

If the coke content is very low in comparison with the coke burn capacity of the CCR unit, the operation can be limited in one of a few ways. A minimum gas flow is required to ensure the catalyst is properly dried before leaving the regenerator and returning for reduction.

(2014) Question 26: What are options for disposition of the caustic regeneration outgas stream associated with an LPG or gasoline caustic treater? What measures have you successfully used to prevent fouling, pluggage, and corrosion in this line?

The caustic treating off gas stream is primarily air that has been partially depleted of oxygen during the oxidation of mercaptides to disulfides in the caustic regeneration step.

(2014) Question 27: What impacts are you seeing in naphtha processing units from contaminants suspected to come from shale crudes (e.g. tramp amines, chlorides, fouling)? What are you doing to mitigate these impacts?

Tramp amines, chlorides, and fouling related to processing of Shale Crudes (or more specifically, Tight Oils) are issues that are of concern on the Crude Unit. I am not aware of issues specific to the gasoline pool and blending downstream of the crude unit.

(2014) Question 28: What is your best practice for determining the maximum allowable temperature rise in hydrotreating beds? What solutions do you have for managing temperature rise?

Operating philosophy regarding the maximum allowable temperature rise in hydrotreating beds from a design perspective is determined by several factors.

(2014) Question 29: What are your current best practices for protecting the charge heater from backflow?

Our design practice for a gas only heater uses a check valve at the outlet of the heater mainly to cut down on the chance of liquid flowing back into the heater during a compressor trip.

(2014) Question 30: What is your minimum charge heater firing limit, especially when highly heat integrated or when processing cracked stocks? Do you have any hydroprocessing units run without firing the charge heater?

The low firing limit is caused by burner instability. Heaters can be turned down by completely shutting off some burners; but there is also a firebox temperature component. Burner instability would be noticed visually – examples being flickering, irregular flame pattern plus increased CO emission.

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