Q&A

(2011) Question 58: Some crudes contain fine particles which result in poor desalting and/or high sludge generation. How are you managing this? Are there specific strategies for treating desalter brine separately (ahead of the wastewater plant)?

Along the lines of Ron’s last point on secondary treatment of brine, some refineries have installed diversion tanks to receive the effluent water when the mud wash is being used.

(2011) Question 59: What are revamp best practices to minimize fouling in crude preheat trains? What services are typically the most difficult? What exchanger technologies have proven most successful?

What are revamp best practices to minimize fouling in crude preheat trains? What services are typically the most difficult? What exchanger technologies have proven most successful?

(2011) Question 60: Assuming good desalting, what are the common / best practices, control ranges and testing frequency of overhead boot water for chlorides - with and without caustic injection?

While general limits are assigned for overhead chloride levels, the reality is that these are simple rules of thumb and should not be relied on to provide satisfactory corrosion control for most systems.

(2011) Question 61: What test methods identify acids (other than HCl) in crude tower overhead water?

What test methods identify acids (other than HCl) in crude tower overhead water?

(2011) Question 62: What options do you use to manage or mitigate high carboxylic acids/TAN in jet/kerosene?

What options do you use to manage or mitigate high carboxylic acids/TAN in jet/kerosene?

(2011) Question 63 What is your refinery's first stage vacuum ejector configuration (single or parallel, idle/standby or all in service)? How do you evaluate your ejector system to determine if it is properly sized and performing optimally? Have you made any modifications to reduce steam consumption?

Typically, vacuum unit ejector systems have three ejector stages in series. Large crude vacuum units have multiple three-stage ejector system in parallel.

(2011) Question 64: What are the impacts on coker operation (yields, capacity, energy, coke quality) of excess VGO (1000F-) in the feed?

Our El Dorado facility has transitioned from a 950o F HVGO/VTB cut point coker feed to a +1075 F while maintaining a fairly constant feed rate to the delayed coker unit. Our experience has seen coke and off-gas yield increase while HCGO yield decreases.

(2011) Question 65: What are the impacts on coker operation (yields, capacity, energy, coke quality) of FCC slurry oil in the feed?

When one of MPC’s refineries starts processing heavy Canadian resid, they add 5 to 10 volume percent of slurry oil in the feed to mitigate making shot coke. The slurry also helps meet anode grade specifications on metals and sulfur. Processing slurry backs out resid processing which can impact unit economics.

(2011) Question 66: How does recycle affect time between coker furnace decokes/spalling?

Natural recycle helps to keep asphaltenes in solution; therefore, higher recycle tends to decrease furnace fouling assuming a constant furnace feedrate. Higher natural recycle reduces liquid volume yield and increases furnace firing which can impact unit economics.

(2011) Question 67: With double-fired heaters, how long do you run between decokes (mechanical or steam-air)? What is your steam spalling interval? How much velocity steam do you maintain?

We have 8 operating Delayed Cokers across our Refineries. Of these, 2 have double fired heaters and others have conventional single fired heaters. With similar feed and Coker operating parameters, the double fired heaters are expected to have longer run length.

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