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(2010) Question 25: Besides high reactor temperatures and flow maldistribution, what are other causes of high gas and LPG yields in a hydrocracker have you experienced?

Hydrocrackers typically process heavy gas oils into distillate-range material. The gas oils are catalytically cracked at high pressures in the presence of hydrocracking catalyst and hydrogen. The reaction is exothermic and consumes a relatively large quantity of hydrogen. High gas and LPG yields would be generally undesirable in a properly operating hydrocracker.
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(2010) Question 33: How do refiners avoid De-isobutanizer (DIB) column/reboiler fouling in sulfuric acid alkylation? What process conditions on the column do you use to detect this fouling? What process modifications do you take to minimize the impact of this fouling?

Fouling in the DIB column is almost always caused by salt deposits. These salts are typically sodium sulfate and sodium sulfite but can also contain calcium or magnesium if the effluent treating water is not demineralized. If these water-soluble salts are present in the DIB feed, the water will evaporate once inside the column leaving the solids behind.
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(2010) Question 36: What are the best practices for maximizing catalyst run length in NHT units that are limited by reactor pressure drop?

Marathon’s experience with NHT fouling has been primarily corrosion products from upstream units and oxygen related polymerization of the naphtha. The use of feed filters can help minimize the effects of corrosion products. Oxygen related polymerization has impacted our NHT units from air leakage across intermediate naphtha storage tank seals and in purchased naphtha.
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(2010) 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.
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(2010) 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.
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(2010) 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.
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(2010) 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.
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