| American Fuel & Petrochemical Manufacturers

Question 46: What is the panel's experience with in-line blending and in-line certification? What are the main differences between in-line blending and certification?

For clarity, a common definition of “in-line blending” is required. Marathon defines in-line blending as a system that pumps multiple blend components from individual tanks, which are typically “live” (either receiving or capable of receiving components from a process unit or pipeline delivery) into a header. The header generally contains static mixing to ensure homogeneity of the blend.

Question 45: In Udex extraction units, what options (process variables / solvent composition / solvent type) do you employ to improve aromatic recovery without compromising unit capacity?

In Udex extraction units, what options (process variables / solvent composition / solvent type) do you employ to improve aromatic recovery without compromising unit capacity?

Question 44: Contaminants in aromatics extraction unit feeds such as chlorides and oxygen are difficult to measure, and can lead to operational issues (such as fouling / corrosion / erosion, etc) in the extraction unit. In your experience, what are the primary effects of these contaminants, and how can one manage these impacts?

Most of Marathon’s experiences with contaminants that affect solvent quality are with oxygen. Oxygen can enter the unit from solvent storage, feed, and re-run tanks. Any vessel operating under a vacuum can also be source of oxygen. Most of our issues with corrosion have occurred in the stripper and recovery column reboilers.

Question 43: In both Extractive Distillation and Liquid-Liquid Extraction units, foaming in the Extractive Stripper column leads to solvent carryover and unit upsets. What are the determinants of foaming, and how do you determine foaming risk? Is continuous antifoam injection necessary? What are the countermeasures do you take to minimize this risk?

Marathon has two liquid-liquid extraction units. Both are fed from reformers. We continuously inject anti-foam into the stripper feed. The only foaming events we have observed have been after the loss of anti-foam injection.

Question 42: In your experience, what are the typical causes of damage to the top of the regenerator inner screen?

The typical cause for damage in the top 2-3 ft of inner screen is metal fatigue due to thermal cycling.

Question 41: Do you have any experience with plugging of chloriding agent injection points in regenerators? How has this been overcome?

The chloride injection line has a nitrogen purge connected with the intent to sweep the chloride into the chlorination gas line. In most designs, the nitrogen and organic chloride line join together before the chloride on/off valve. When the chloride valve closes, both chloride and nitrogen sweep are stopped.

Question 40: Has anyone experienced high chloride levels in off gases from the lock hopper of a pressurized regenerator? What are the consequences of the high levels (i.e. fouled burner tips)? What are ways to mitigate the problem?

Marathon has not experienced any high hydrogen chloride concentrations in Lock Hopper off gases from the two CycleMax regenerators that we operate. We have also not experienced problems with fouled burner tips due to high hydrogen chloride in the fuel gas to a heater.

Question 39: With lower severity requirements due to ethanol blending and corresponding reduced coke make in the reformer, what changes are you making in regards to reformer operation? What opportunities does this evolution present for both CCR and semi-regen units?

Increased ethanol blending has reduced the severity of the reformers on average 2 octane numbers. This has increased reformate yield and decreased hydrogen production. Although the octane boost realized by ethanol blending reduces overall pool octane requirements, minimum reformer severity may be dictated by octane requirements of premium gasoline grades, or by refinery hydrogen requirements.

Question 38: What measurements and criteria do you use to decide when to change your gas and liquid chloride absorber material? How do you determine the selection of absorber material?

For both gas and liquid service, Chevron monitors the inlet HCL/Total Chloride and replaces the adsorbent/molecular sieve based on material balance loading of chloride on the adsorber media. Chevron does monitor adsorbent outlet HCL/Total Chlorides, but as a best practice will change the adsorbent material before vendor maximum loading if breakthrough has not occurred.

Question 37: Silicon poisoning of NHT catalysts has been observed in refineries without coking units. In your experience, what are the potential sources of silicon and what are the best practices to manage risk of such poisoning?

Marathon has had to deal with issues of non-coker silicon in naphtha’s since at least 2001. For background purposes, it is Marathon’s experience that silicon blocks the pores on hydrotreating catalyst and can impact catalyst activity. In severe cases, silicon breaks through to the reforming catalyst can occur where it can form silicon dioxide during the regeneration process which can cover the platinum sites.