Q&A

Question 16: A number of refiners are adding a chloride dispersant to address FCC main fractionator overhead system plugging issues. What is your experience with these products and have you had issues with downstream gasoline product quality?

Processing of increased amounts of imported FCC feed, both gasoline and reduced crude, results in increased chloride salts in the main fractionator, which is usually a result of sea water contamination of transfers. Ammonium chloride salt dispersant is a chemical, which can be used to move or disperse ammonium chloride salts to prevent pluggage of the FCC main fractionator.

Question 17: What minimum nozzle velocities are required in air and steam distributors to prevent catalyst backflow and subsequent erosion? Please consider both upward and downward pointing nozzles.

The FCC has many distributors: combustion air, stripping steam, feed nozzles, and torch oil. Many routine FCC problems are the result of poor distributor operation; for example, poor yields due to poor catalyst/oil contact, poor stripping due to lack of catalyst/steam contact, and excessive attrition due to distributor damage.

Question 18: Some refiners have installed gas injection in FCC secondary cyclone diplegs to increase capacity and avoid defluidization problems. Please describe your experience operating with gas addition in the diplegs and any maintenance issues. What advice would you give to others considering this installation?

Cyclone dipleg aeration is a technique used to improve cyclone dipleg fluidization. It involves adding steam, a stream of purge gas—usually air or steam—to the dipleg just ahead of the trickle valve.

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.

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