Q&A

(2017) Question 33: What conditions are tied to fired-heater shutdown interlocks? Do these cause an immediate shutdown, or are there any time delays built into the logic? If so, how long of a time delay do you use? Are there any operating conditions that would allow interlocks on fired heaters to be bypassed?

Marathon Petroleum Corporation (MPC) standard practices rely heavily on the guidance recommended by API 556. Most of our heater shutdown interlocks are derived from this API Recommended Practice. Our internal practices are intended to prevent a heater explosion due to uncombusted fuel in the firebox or a tube rupture that can lead to an explosion or uncontrolled fire.

(2010) Question 49: What testing procedures do you use for emergency shutdown valves? What are the parameters you measure and what are acceptable values?

The appropriate required testing of emergency shutdown valves is included in each Marathon refinery’s Mechanical Integrity (MI) program, complying with OSHA’s Process Safety Management regulation and EPA’s Risk Management Plan regulation.

(2010) Question 50: Chemical cleaning of towers and vessels prior to entry is being used to reduce time to entry. What practices are you employing and how much time is saved?

Our chemical cleaning practices for Crude/Vacuum and Coking units have evolved over many years. The starting point in most cases, after feed is out and the unit has circulated down, cooled and pumped out, is a flush with diesel or LCO followed by a good steamout.

(2010) Question 52: What areas of a delayed coker are susceptible to naphthenic acid corrosion? How do you determine the maximum allowable TAN for these areas?

The primary areas of concern include: •Coker feed circuit above 450 °F •Bottom section of the fractionator, including internals •Heater charge pumps and associated piping •Heater tubes.

(2010) Question 53: During the coking cycle, how are drum skin temperatures used to monitor drum wall condition?

Monitoring drum wall conditions during the drum cycle is best performed using strain gauges. Each strain gauge location will typically be fitted with gauges in both the axial and hoop directions and have an associated skin thermocouple.

(2010) Question 61: In your experience, what is the effect of crude oil compatibility on crude unit preheat exchanger fouling? Are there any correlations used to predict fouling?

Since there are only isolated instances of fouling in the “cold train” exchangers prior to the desalter(s), we will assume this question is directed more towards the “hot train” exchangers.

(2010) Question 62: What are the refiners experiences using static mixers in place of, or in conjunction with, traditional mixing valves at the desalter?

Years ago, many refiners installed static mixers in desalters, as opposed to traditional mix valves, to improve contacting of water and oil at a lower pressure drop. In theory, this was a good idea, but in practice it has not worked well.

(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 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.

(2019) Question 38: What are your guidelines for cleanliness of reactor vessel and overhead lines during Turnaround?  Do you have limits on reactor temperatures during dry-out to prevent the ignition of coke in the reactor?  What actions do you take if coke starts to burn?

What are your guidelines for cleanliness of reactor vessel and overhead lines during Turnaround?  Do you have limits on reactor temperatures during dry-out to prevent the ignition of coke in the reactor?  What actions do you take if coke starts to burn?

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