Q&A

(2017) Question 46: What is your design service life of atmospheric tower overhead heat exchangers? How does that compare to actual service life? What do you do to better manage corrosion and improve reliability of these heat exchangers?

Heat exchangers are designed for heat recovery and only rarely for corrosion control. The designer’s tool for reliability is to use upgraded materials of construction. Over the years, those on our team have seen even Hastelloy C276 and titanium being used.

(2017) Question 47: What correlations do you use to predict cracked gas make in a vacuum tower from atmospheric tower bottoms based on feedstock properties and heater outlet temperature?

In the past, vacuum towers’ flash zones have operating at or below atmospheric tower flash zone temperatures. These units relied on the vacuum to increase heavy gasoil yields from the atmospheric resid without running the risk of thermal cracking associated with higher temperatures.

(2017) Question 48: What are your design and operating guidelines for vacuum tower bottoms versus crude heat exchangers such as minimum velocities, fouling rates, and pressure drop, and which process fluid should be on the tube side versus the shell side?

KPE believes the typical design for a vacuum bottom versus crude exchanger is for the crude to be on the tube side and the vacuum bottoms to be on the shell side. Most facilities I see have this setup as weli.

(2017) Question 49: How do you use today’s Advanced Process Control (APC) technology to achieve crude unit operation that supports short-and long-term planning goals? How do you achieve alignment between the crude unit APC and those of downstream units?

Without proper resources and attention, Advanced Process Control (APC) technology may experience inconsistencies as applied to crude units. Refineries where crude slate varies frequently may struggle capturing the value that APC provides for steady controls and optimization. Mode-based APC may be applicable, but irregularities in crude compositions may still provide hurdles.

(2016) Question 17: What are your strategies for managing feed sulfur to reforming units? What are the pros and cons of the different approaches?

It is desirable to have a small amount of sulfur in the feed for CCR reforming units in order to reduce the risk of metal catalyzed coke (MCC) formation and heater-tube carburization and dusting. The sulfur interacts with the chromium and the iron to form a protective layer that reduces the penetration of carbon into the metal.

(2016) Question 18: The increased production of light straight-run (LSR) from crude units is likely to have an impact on refiners’plans for Tier 3 compliance. What strategies do you employ in order to manage this issue?

Tier 3 drives hydrotreating of essentially all light naphtha streams. Since most United States refineries have FCCs, it is usually desirable to hydrotreat other gasoline streams more completely to minimize the FCC naphtha olefin saturation and the associated octane loss

(2016) Question 19: What range of sulfur targets for hydrotreated FCC gasoline do you anticipate for Tier 3 operation?

The sulfur target for hydrotreated FCC gasoline is very site dependent. But where possible, it is desirable to hydrotreat all other gasoline streams fully so that the FCC naphtha can be treated as mildly as possible. Deeper desulfurization for FCC naphtha results in increased olefin saturation with the resultant octane loss.

(2016) Question 20: When is it appropriate to neutralize austenitic stainless-steel equipment to protect against stress corrosion cracking (SCC)? What neutralization procedures and methodologies do you recommend?

Austenitic stainless steels (200-and 300-series steel) are the most common type of stainless steels. Austenite refers specifically to the geometry of the steel (face-centered cubic crystal). These types of steel are most typically recognized as non-magnetic. Austenitic steels are widely used in the industry because they have very desirable mechanical properties. Their austenitic structure is very tough and ductile down to absolute zero. They also do not lose their strength at elevated temperatures as rapidly as ferritic iron base alloys.

(2016) Question 21: What programs or systems do you employ to monitor hydrotreater furnaces and prevent tube failures and loss of containment? Can you share your experiences using technologies to implement online temperature monitoring of tube skin temperatures?

In nearly all hydroprocessing heaters, MPC has installed tubeskin thermocouples in order to provide continuous monitoring of tube metal temperatures to the DCS (distributed control system) operator. These thermocouples are strategically located in the heater at the areas with the highest estimated maximum heat flux.

(2016) Question 22: Describe your strategies for optimizing the pretreat and cracking catalyst cycles. How does this strategy vary when operating between maximum naphtha and maximum distillate modes? How does this impact catalyst selection for the next cycle?

Marathon Petroleum Company has adopted the philosophy of optimizing the hydrotreater and hydrocracking catalyst together as one unit. We do not measure nitrogen slip from the hydrotreater section, but rather allow the hydrocracker apparent conversion dictate adjustments to the pretreat section.

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