Q&A

(2010) Question 63: Certain crudes are treated with H2S scavenger to meet a 10 ppm or less specification in the vapor space. In your experience, what is the disposition of the reacted and unreacted scavenger additive through the crude unit? Will this product and/or associated byproducts create corrosion or product quality issues in the crude unit or downstream units?

The majority of H2S scavengers used today are water-soluble, cyclic amines which can quickly react with H2S, forming a water-soluble reaction product. However, these amine-based scavengers are not without potential problems. As formulated, these scavengers often contain un-reacted amines.

(2010) Question 64: Please discuss the latest tray and packing technologies for improved fractionation efficiency in existing crude and vacuum units. In particular, what is the effectiveness in terms of fouling/plugging and resulting run length?

Well designed and installed fractionator tray, packing and liquid/vapor distributor equipment are one important tool in ensuring the crude/vacuum unit is able to reach its targeted runlength. A good understanding of operating parameters along with measures and systems to ensure that operation stays within those parameters are the other tools necessary to meet that targeted runlength.

(2010) Question 65: What methods do you use for heat recovery from furnace flue gas equipment at ~260°C (500°F)?

Air preheat systems are used for recovery of heat from flue gas down to app. 300 deg F. The 300 deg F temperature is set based on limiting dewpoint corrosion on cold metal surfaces. This temperature will vary depending on the materials employed, the sulfur content of the treated fuel gas, and cold ambient temperature.

(2010) Question 66: Flare gas recovery systems are currently being engineered and installed in refineries. Please comment on your experience with these recovery systems, particularly with their reliability and maintenance.

Our oldest flare gas recovery system has been in place for thirty years. This installation has sliding-vane style flare gas compressors. Our newer applications have liquid-ring compressors.

(2010) Question 67: Have you experienced coking or other fouling of reboilers in naphtha distillation service (splitter, debutanizer, etc.)? If so, what operational or design changes did you implement to eliminate this problem?

Two types of fouling are common in naphtha reboilers. The first type of fouling is generated as a result of the more reactive cracked stock hydrocarbons and is typically seen only in units like Cokers or FCCUs with a cracking process. The second type of fouling is a more complicated issue related to the presence of sulfides in the naphtha and can be seen in straight run units like the Atmospheric Crude.

(2010) Question 68: Do you see any benefit in continuing to steam strip crude tower distillate cuts since these side streams require further processing in down stream hydrotreaters?

We have observed definite benefits to steam stripping the distillate cuts and have been working to determine whether the benefit is worth the cost. The main purpose for distillate side strippers is to control product flash with a secondary purpose of lifting lighter material and affecting the product cuts.

(2010) Question 69: What do you see as the critical considerations for wash bed design in high C-factor vacuum columns? How does one determine bed type, depth, and appropriate wash oil distributor design?

A new vacuum column will typically be designed for a C-factor of 0.36 ft/sec above the wash zone which is normally the section with the highest vapor velocity. A high C-factor situation (say above 0.43) would then involve an existing unit operating well above its original design point.

(2010) Question 70: How can you minimize the possibility of ignition and fire in the structured packing of main fractionators after they are opened for maintenance? Do you use chemicals to improve this procedure?

Zyme-flow products have been used in our past FCC turnarounds to mitigate pyrophoric compounds as well as decrease the amount of time to hydrocarbon free the main fractionator and associated pumparound circuits.

(2010) Question 71: For the main column, "tri lines" can be utilized to monitor bottoms level. When other level instruments are being verified or have failed, what are the best operating and safety practices being employed to verify the level? What do refiners use to monitor and control level in the bottom of the main column?

For the main column, "tri lines" can be utilized to monitor bottoms level. When other level instruments are being verified or have failed, what are the best operating and safety practices being employed to verify the level? What do refiners use to monitor and control level in the bottom of the main column?

(2010) Question 72: With advance controls on the FCCU and gas plants, what are refiners doing to train new operators and keep their experienced operators sharp and ready to handle FCCU upsets and emergencies? Are refiners using simulators to help with the training and retraining?

Sunoco employs Dynamic Matrix Control (DMC) on all the FCC gas plants and DMC on reactor and regenerator systems. One FCC has a complete process training simulator, and we are in the process of installing simulators on all of our FCC’s.

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