Q&A

(2016) Question 36: Which refinery water sources do you accept for hydrotreater water wash (e.g., stripped fractionator overhead water, stripper sour water, etc.)? What are typical water quality guidelines?

Water wash systems must be designed well, with good water contact and draining, or the wash can create significant corrosion concerns, potentially resulting in process safety incidents. MPC experienced this first-hand with an intermittent wash system on an NHT unit.

Question 37: What is the impact of CO (carbon monoxide) and/or CO2 (carbon dioxide) on noble metal catalyst performance?

CO and CO2are poisons for noble metal catalysts, with CO being a very strong poison. Contamination level as low as 50 to 100 ppm can result in significant and permanent loss of activity. CO should be limited to less than 10 ppm. In our experience, units which achieve long cycles (10 years plus) typically have CO levels less than 5 ppm.

(2016) Question 38: What do you see for the future of ebullated bed technology considering changes in crude quality and availability?

With the worldwide requirement for higher conversion of residue into lighter, more valuable transportation fuels such as diesel remaining firmly in place, we very much see ebullated-bed (EB) residue hydrocracking building on its current trend as a bottom-of-the-barrel upgrading technology of choice going forward. Investment in this commercially proven, well-established technology is a way to increase complexity and ensure long-term survival in an increasingly volatile marketplace.

(2016) Question 39: Please summarize the current status of slurry hydrocracking technology commercialization.

Slurry hydrocracking technology has been commercialized in China (VCC) and Italy (EST) in the past two to three years. Both facilities have demonstrated expected performance, including conversion and selectivity. The reliability of slurry hydrocracking is still an open question as these units have only been in operation for a short time. Additional VCC commercial units are scheduled for startup in the next 12 months.

(2016) Question 40: As it relates to overall catalyst cycle life management, please address the following issues: What are typical cascading practices for catalyst reuse after regeneration and eventual disposal that you employ? What quality control, catalyst properties and performance specifications, and/or warranties do you have in place for regenerated catalysts? What are some of the key decision criteria you use in determining whether to send a catalyst for metals reclamation, r

First, a response to the question: What are typical cascading practices that you employ for catalyst reuse after regeneration and eventual disposal? As the leading catalyst regenerator, Eurecat sees NiMo and CoMo hydrotreated catalysts (regenerated and regenerated plus rejuvenation) in ULSD, jet, kerosene, naphtha, and gas oil hydrotreating units.

(2016) Question 41: What are the considerations you use for extending hydrogen plant catalyst life cycles (i.e., lower production rates, furnace tube failure, etc.)?

There are many parameters affecting the hydrogen plant catalyst life cycles, such as lower production rates, furnace tube failure, unplanned plant shutdowns, larger catalyst volumes, elevated energy consumption, and finite ZnO/S (zinc oxide/sulfur) capacity. Lower Production Rates will obviously result in longer catalyst lifetime due to a lower gas velocity over the catalyst.

(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.

(2016) Question 44: What issues do you consider to establishing a purchased crude oil custody transfer Best Practices from various sources?

Custody transfer requirements and regulations can differ by world area, by modality, and even by company. Most companies follow API (American Petroleum Institute) standards for the measurement sampling and custody transfer. Generally, there is a pay meter and a check meter. The contract specifies what happens when there is too large of a discrepancy between those two meters.

(2016) Question 45: What criteria and requirements that you use to determine mixing equipment for crude tankage? How do you map the sludge level? What methods do you use for sludge removal to shorten time to clean the tank?

Question 45 is actually a combination of three questions. The central issue here is the sludge. There are many purposes of using crude tank mixtures, many of which are listed on the slide. The purpose of the crude tank mixer might be for homogenization–in terms of density, viscosity, or temperature–or its purpose may be to control BS&W to reduce or eliminate sludge or the blending of crudes.

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