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(2019) Question 28: In light of IMO (International Maritime Organization) 2020 and the potential for shipping intermediate streams from refinery to refinery, what are your plans to ensure H2S specification in the vapor space is met, either at the shipping or receiving point?

STEVE WILLIAMS (Marathon Petroleum Corporation)

•    Movement of intermediate streams from refinery to refinery has been a common practice, including movement of heavy oils.  This activity is expected to increase following implementation of the IMO 2020 rules reducing the sulfur content in maritime

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(2019) Question 30: What progress have you made in crude analysis in a timely manner, establishing stability criteria, scheduling blends, and mitigating processing constraints when blending multiple crude unit feedstocks?

XIOMARA PRICE (SUEZ Water Technologies & Solutions)
Crude blending is still largely based on the economics of the blends and less on the processing constraints that may exist.  Real time analytic and predictive tools are available to the industry to help quickly determine the blends relative

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(2019) Question 32: Where are ammonium chloride and amine hydrochloride salt found in your crude unit? What is your best practice to monitor and mitigate the resulting corrosion and fouling?

Ammonium chloride and amine hydrochloride salts can form in the top section of the Atmospheric and Vacuum Towers, and the overhead exchangers of the tower. The formation of these salts is a function of partial pressures which dictated by the concentrations of ammonia, amines, chlorides in addition to operating conditions such as overhead temperature, pressure, steam flow rate and hydrocarbon flow rate.
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(2012) Question 69: How do you detect that amine salts are forming and causing corrosion, either in the fractionator or other locations ahead of the water dew point? What are chemical and operational strategies for mitigation?

We have the chemical service vendor perform routine calculations for ammonia and/or amine salt points. We typically monitor the water dew point ourselves. The amine salt point is to be differentiated from the ammonia chloride salt point. Depending on the amine, a salt point can be higher, and often is.
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(2012) Question 70: What are your experiences with processing oil sludge in the delayed coker?

One of our delayed cokers does process crude rag layer draw, wastewater sludge, and oily water. I think they primarily process the crude rag layer, however. What we do here is introduce the sludge after we have steamed the coke bed and established the quench water flow. We then temporarily remove the quench water to allow the sludge injection, and then we maintain a minimum temperature – I think it is around 600°F – to ensure that no oil accumulates in the cutting water.
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(2012) Question 71: Is there any test method for performance evaluation of silicon-based antifoam agent used in coker?

Don mentioned the ASTM test procedure. It may also be beneficial to conduct elemental silicon loading. Silicone is a known molecule: dimethylpolysiloxane. The amount of elemental silicon introduced into the drum over a period of time can be tracked and compared with silicon in the distillate. Generally, the biggest step change to silicon loading is improving the chemical feed system.
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(2012) Question 73: What is your experience with coke bed instability?

We have seen coke beds collapse during the beginning stages of the quench water addition. We have had operational problems because we were not able to get the quench water into the coke bed. We even tried alternating back and forth between the stripping steam and the quench water, but we were not able to penetrate the coke bed with the quench water.
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