Q&A

(2018) Question 56: Excluding nickel passivation. How does antimony use in the reactor riser impact the FCC operations and equipment?

Antimony functions by attaching to a fresh Nickel molecule in the FCC feed and preventing it from laying down on the surface of the catalyst. Efficiency of antimony in passivating Nickel and tendency to have side effects is highly dependent on the carrier and distribution method. Antimony can be water based or oil based, with oil-based antimony having a higher lay down efficiency (approx. 85% typical) as compared to water based (approx. 65%).

(2018) Question 57: How are you optimizing the use of wet gas scrubbers caustic use and SOx additives?

You can utilize a SOx additive in addition to a Wet Gas Scrubber system in order to reduce caustic consumption and minimize cost. Utilizing a SOx additive can be optimized by calculating the caustic savings + value of additional liquid sulfur produced - the cost of the Sox additive.

(2010) Question 34: What has been the experience of refiners operating selective hydrotreating of FCC naphtha regarding gum formation potential of the low sulfur gasoline? Is gum inhibitor addition a recommended practice?

Gum potential exists with unsaturated hydrocarbons (olefins or diolefins) stored in refinery operations with oxygen as a free radical. Organic sulfur and nitrogen compounds remaining in FCC gasoline product can form gums in the presence of olefins and oxygen.

(2010) Question 47: What are the best practices for corrosion probe selection, installation and reliability, especially in high temperature and/or high H2S environments?

Some things to consider when selecting and installing corrosion probes are to match the metallurgy of the probe to the pipe.

(2010) Question 48: In your experience, what is the preferred online (non-destructive) method to identify risk of HIC (hydrogen induced cracking) in gasoline processing units?

The preferred method of identifying the risk of hydrogen induced cracking is to measure the permeation or flux of hydrogen on the outside surface of the equipment and correlate this to the corrosion rate on the inside of the pipe.

(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

(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

(2019) Question 31: Is intermittent or continuous mud washing considered your best practice and why?

STEVE WILLIAMS (Marathon Petroleum Corporation)
• Mud wash is utilized to help keep the bottoms of a desalter vessel relative free of solids build up.
• Utilizes a distribution header with nozzles located near the bottom of the desalter to create a liquid disturbance at the bottom to preclude

(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.

(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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