Q&A

(2016) Question 42: What are your typical H2S (hydrogen sulfide) detection and monitoring methods used on heavy oil fractions being transported via truck, rail, or barge? What are the mitigation options you employ?

We see typically dragger tube testing and head space H2S monitors being used. Mitigation is still done, for the most part, with chemical additives. The most commonly used additives are from the triazine family. As a result of the concerns that refiners have with some of the existing triazine and non-triazine (e.g., glyoxal) being used with respect to the impact on downstream equipment, Nalco Champion has developed both non-triazine, non-acidic (non-glyoxal), and low nitrogen alternative H2S scavengers.

(2016) Question 43: Have you experienced high corrosion rates in carbon steel piping in resid service operating below 500°F? Please comment on corrosion mechanisms.

High corrosion rates have been experienced in heavier streams, like RCO (reduced crude oil) and vacuum residue operating at a temperature of 450 to 600°F. The role of naphthenic acid corrosion is difficult to determine in such streams with respect to the TAN (total acid number) distribution, temperature and velocity. The key precursor is sulfur species which causes “sulfidic corrosion” in such residue streams.

(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 89: In shifting from partial burn to full burn in a side by side unit, what has been your observed impact on the NOx emissions? What is necessary to achieve 20 ppm NOx?

Several Grace customers successfully operate with NOx emissions less than 20 ppm in full combustion without the use of NOx removal hardware in the flue gas circuit.

(2010) Question 90: Does any refiner use an on-line particulate emissions (PM) analyzer to measure PM concentration and/or particle size distribution in the flue gas? Are any of these analyzers using continuous emission monitoring systems (CEMS)? How reliable and accurate have these systems been?

Sunoco currently has a particulate matter (PM) analyzer in one location on the stack of a Wet Gas Scrubber. It is there to measure Filterable PM only, not particle size distribution. This was installed as a requirement of a local environmental permit.

(2010) Question 91: Assuming the FCCU already has a third stage separator, what are the various options you consider for further reduction of particulate emissions (PM) and what is the expected level of PM to be achieved?

The first thing to consider is the fourth stage collector. For designs that re-introduce the collected fines downstream of the expander, a fourth stage collector with fines removal and filter on the TSS underflow gas will aid in reducing PM.

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