Q&A

(2016) Question 16: What is your Best Practice for inspecting and preventing erosion in CCR lift lines?

In CCR Platforming™ units, the movement of catalyst through the lift pipe results in contact between the catalyst pills and the inner surface of the lift pipe.

(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.

(2015) Question 1: When preparing reformer or isomerization vessels for maintenance, do you measure the benzene content of the unit? If so, what methods and locations are monitored and what criteria are used to establish safe levels for work to begin?

The corresponding OSHA regulation 1910.1082 states that the actionable limit for contact with the airborne benzene is 0.5 ppm (parts per million) on an eight-hour time-weighted average (TWA) and 5 ppm for a 15-minute TWA basis. In our facility, we have set our practices to meet that standard.

(2015) Question 2: What are your Best Practices concerning the potential for flash fires in dust collectors and vent drums in a reformer's continuous catalyst regenerator when performing maintenance?

Our main concern here is iron sulfide, which is pyrophoric; meaning that if it is exposed to air, it will self-ignite. There is also hydrocarbon present, so you can get a sustained fire if these lights are off.

(2015) Question 3: How have you developed integrity operating windows (IOWs) to follow American Petroleum Institute (API) Recommended Practice (RP) 584? How are the IOWs maintained and communicated to the operating staff?

Shell and Motiva have been on a journey, for well over 15 years, to educate our operators and provide them with the information necessary to operate their units within the safe operating window. The starting point is to define the unit operating window in terms of temperature, pressure, flows, etc.

(2015) Question 4: How will increased production of naphtha from light tight oil (LTO) and Tier 3 regulations affect the economics for alkylate and reformate production? Are there other options for processing light naphtha streams?

That was a great Keynote address this morning because it talked about the LTOs, and Ramón Loureiro described them in detail. A couple of other options are to take the light naphtha through an isomerization unit and separate out the C5s and C6s to possibly get the benzene precursor removed from the reformer.

(2015) Question 5: Automobile manufacturers are considering requiring the use of higher-octane fuels in order to meet a mandated increase in Corporate Average Fuel Economy (CAFE) standards. What strategies might you employ should demand for higher octane gasolines increase?

Even without potential regulatory increases in minimum octanes, in a low-price gasoline environment, it seems clear that lower prices result in premium gasoline demand.

Question 6: Do LTOs contain higher concentrations of nitrogen? If so, how has this higher concentration effected gasoline processing units?

The LTOs generally do not contain a higher concentration of nitrogen. LTOs are typically characterized as light, sweet, low-sulfur, low-nitrogen crudes. For example, the Eagle Ford and the Bakken nitrogen typically contains less than 2 ppm. Nonetheless, the gasoline processing units are impacted when refineries process higher percentage of the LTOs because of the crudes.

(2015) Question 7: Recognizing that onstream factor is an important component of margin capture, what are the common areas of improvement for each of the gasoline processing units to reduce downtime or increase turnaround interval?

Turnaround time intervals approaching 60 months are becoming more frequent as processes and procedures improve over time. The incentive to extend the turnaround cycle beyond 60 months does nothing more than prolong turnaround times.

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