| American Fuel & Petrochemical Manufacturers

Question 52: What are your Best Practices for a waterwash system to control corrosion in delayed coking fractionator overhead and light-ends systems?

The overhead waterwash for a delayed coker main fractionator system is the same as for an FCCU main fractionator overhead. The volume of water required is calculated based on what is needed to condense the water present with an added excess; typically, this is 25%. In some cases, the site, instead, bases the washwater requirement on the feed to the tower.

Question 51: What key parameters of coker furnace tube design and metallurgy do you experience that can impact run-length? What metallurgy do you use specifically to increase run-length and tube life?

For many years, our standard has been 9 Cr-1 Mo tubes. We also have numerous Amec Foster Wheeler delayed coker heaters that have been retubed with347SS.

Question 50: In the absence of individual dipleg sample points, how do you manage corrosion in the vacuum overhead system?

Although it is not fully a Best Practice, the monitoring of the combined stream coming off of the overhead accumulator has historically been used successfully.

Question 49: What criteria for materials of construction do you use for structured packing at the different sections of the crude, vacuum, and coker towers? What criteria do you use to replace packing during turnaround?

316SS works well against naphthenic acid corrosion attack. Inconel 625 is another alternative for extreme service conditions, but it is generally not required.

Question 48: What are important considerations for evaluating the methods used for fouling detection and mitigation in preheat exchangers and furnaces in crude and coker units?

Methods for fouling detection and quantification need to be capable of normalization to minimize ‘noise’ from system variables. Complex heat transfer rating programs can be used for this purpose. These programs must be capable of looking at heat exchanger networks as systems, as well as individual exchangers.

Question 47: Given the increased volatility of crude and product prices, what additional steps do you take to adjust your crude unit cutpoints to maximize profitability?

In order to have the flexibility to operate with a wide range of crude APIs and the ability to vary product draws to maximize revenue, a complete study has to be carried out to analyze crude unit operation between the bracketed crudes, including the effect on preheat train, furnace, and column operation

Question 46: What measurement methods (i.e., analytical, and/or online analyzers) do you use in crude and coker units, and product quality management? How do you use the information to improve unit reliability and profitability?

instrumentation was used in crude unit feed management in one project to ensure that the correct crude blends were being used for various crude units.

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.

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.

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.