Q&A

Question 19: FCC revamps commonly include technology upgrades, which increase the catalyst circulation rate, which then increases the stripper flux and reduces the stripper residence time. Please describe your experience with the high flux stripper and its performance. What is the maximum flux you have achieved? What is the minimum residence time you have achieved? Will the use of high efficiency stripper internals reduce the required residence time?

In addition to technology upgrades, capacity creep is a major factor contributing to ever-higher catalyst circulation rates. Together, these factors are indeed forcing refiners to push the boundary of stripper flux and residence time experience.

Question 20: Several refiners are considering continuous operation of the combustion air heater to maintain a minimum regenerator temperature when processing light, severely hydrotreated feedstocks. What control systems, design features, and other general precautions should be considered?

Holly is constructing mild hydrocrackers at both of their refineries. Of obvious concern to Operations and Engineering is where the FCC heat elements will settle out.

Question 21: When operating with one or more catalyst coolers on a regenerator, what control philosophy do you employ (e.g., constant heat duty, constant regenerator temperature, etc.)? What are the advantages and disadvantages for each approach? How does operating in full- or partial-burn impact the control decision?

A catalyst cooler is basically a vertical shell-andtube heat exchanger attached to the regenerator. The cooler extracts high quality heat from the catalyst in the regenerator to produce high pressure steam.

Question 22: With the introduction of modern riser termination devices (RTDs) and the advent of severe FCC feed hydrotreating, what is your experience (typical values) with the ash content of the main fractionator bottoms (MFB) product? Please describe the testing methodology utilized and the recommended testing frequency for this stream. What process, practices, and/or equipment changes can be employed to reduce the ash content of the MFB product?

Sunoco’s FCCs operate primarily in resid cracking mode; either atmospheric or vacuum resid, typically without the benefit of upstream feed hydrotreating. We have FCCs with coupled two-stage riser termination devices, riser cyclones uncoupled to the secondaries, and simple RTDs followed by either single- or two-stage cyclones.

Question 49: In the past year, a sulfuric alkylation unit released a significant amount of sulfur dioxide to atmosphere when light hydrocarbon flowed from the reaction zone through the acid blowdown system and into the spent acid tank. What measures do you recommend for preventing this?

We would recommend ensuring that the acid knockout drum be sized large enough to allow the hydrocarbons to disengage in the drum.

Question 50: What is the proper firefighting media to use when putting out a fire when both spent sulfuric acid and heavy hydrocarbon are present (e.g., in a spent acid tank or a diked area that has a layer of hydrocarbon floating on the spent acid)?

The water and acid will interact, which makes water a poor choice. Most of the foams of which we are aware are mostly water. A dry chemical will also react to the acid. So, as always, when you get into a fire situation, there’s some initial assessment that’s required of the fire.

Question 51: Reforming unit stabilizer column top trays and overhead condensers can experience fouling with ammonium chloride salts, which are commonly removed by online water washing of the column overhead. What practices do you employ to reduce the risk of rapid corrosion and the potential failure associated with this fouling and subsequent water washing procedure?

Ammonium chloride salts are a common problem in both naphtha reforming and naphtha hydrotreating units.

Question 59: For a hydrofluoric acid (HF) alkylation unit, what instrumentation do you recommend for controlling HF acid levels throughout the unit?

Generally speaking, the industry is moving more and more toward using nuclear devices for level of protection. At PRSI, we have a major project in place now where we’re identifying crucial areas in our units and are installing nuclear devices in both of our alkylation units.

Question 60: How do you detect leaks in an isomerization unit's steam charge heater? Have you been able to detect a leak before a significant portion of the catalyst bed was deactivated?

The common problem in these units is deactivation of the catalyst by the ingress of water over the catalyst, because water actually deactivates the catalyst. This is a slide of a typical flow scheme for these units, and kind of shows you the conundrum of designing and operating these units.

Question 61: Have you found that you needed to install a methanator upstream of a chlorided catalyst isomerization unit to remove carbon monoxide (CO) from the feed? What is the source of the CO and how much of a difference has the addition of the methanator made to catalyst life? What is the expected payout for the cost of the methanator?

The problem now comes from the oxygen ingress coming in with makeup hydrogen, with the culprit typically being CO and CO2.

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