Filters

(2010) Question 26: What are the best practices for entering the vapor space above an internal floating roof in a gasoline tank

Entering the vapor space above an internal floating roof tank creates a set of somewhat unique safety concerns that must be addressed in a facility’s safe work procedures. The primary hazard is entry into an air atmosphere with some level of hydrocarbon vapor or toxics, and liquid hydrocarbon (gasoline for this discussion) beneath the floor, with wiper seals, pontoons, etc. creating a barrier to prevent conditions within the confined space from changing.
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(2010) Question 27: It has become increasingly common to chemically neutralize / passivate refinery towers and vessels prior to entry. What are the recommended practices for implementing these tasks? In your experience, what conditions trigger the need for chemical treatment?

Although this list is not “all-inclusive”, here are some general recommended practices when chemical cleaning and/or neutralizing towers and vessels. First, there needs to be a single point of contact for the chemical cleaning vendor. This person is responsible for the planning, preparation and execution of the chemical cleaning process. Prior to cleaning, P&ID’s need to be marked up to identify all injection points, steam and chemical flows and even line ups for the chemical cleaning.
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(2010) Question 28: The Clean Air Act required refineries to develop and implement a Leak Detection and Repair (LDAR) program to control fugitive emissions. What is the current status of this implementation and who is responsible for it in a typical refinery management structure: production, maintenance or EHS?

Since the inception of the Clean Air Act of 1955 and multiple amendments through 1990, Leak Detection and Repair or LDAR regulations have been a part of air pollution control. Today’s LDAR programs are governed by Federal and State regulations and agreed orders (consent decrees) that provide the control of fugitive emission leaks from process equipment by requiring equipment inspections and leaking equipment repair.
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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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