Q&A

(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.

(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.

(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.

(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.

(2010) 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.

(2010) 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 1: Historically, instrument air was used to purge FCC reactor instruments. More recently, dry gas or nitrogen is typically used for this service. Please explain the reasons for moving away from air and provide examples of operating upsets that have occurred when using air to purge instruments.

Gas purge streams for instrumentation in FCCU reactor-regenerator service are required to ensure their functionality. For example, the reliability of level- and pressure-measuring devices relies on clear impulse lines. The utilization of a continuous-purge gas stream ensures that catalyst particles are prevented from entering or are swept from impulse lines to keep them clear and reliable.

Question 2: Which type of valve technology or design is typically utilized in units with high catalyst withdrawal rates? Do you continuously withdraw catalyst? From a reliability and safety perspective, what type of hardware are you using for control? What is the best withdrawal line design?

Valve selection for FCC catalyst withdrawal services is dictated by temperature and erosion considerations.

Question 3: Carbonate stress corrosion cracking (CSCC) has been identified as a cause of failure in FCC main fractionator overhead systems. What changes in feed quality, unit operation, or configuration would lead to increased risk of CSCC? What parameters do you monitor to determine whether a system is susceptible to CSCC? Has the problem been significant enough to warrant either comprehensive PWHT in potentially affected areas or localized PWHT when problem areas are identified?

Carbonate stress corrosion cracking, CSCC, is characterized by inter-granular, sometimes branchy, scale-filled cracks. It is believed that ammonium carbonate is the main contributor to the cracking mechanism.

Question 5: What is the shortest possible time between oil out and entry for maintenance on large inventory, high capacity FCC units? How is this achieved?

With FCCs at 27,000 bpd and 9,000 bpd capacity, neither of our units really qualifies for high throughput or large capacity. However, in discussions amongst the members of the panel, we found that throughput and inventory are not necessarily good indicators of how quickly you can move oil-out to maintenance-in.

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