Q&A

(2011) Question 4: How reliable are the dry gas seals on hydroprocessing recycle gas compressors? What are the system components put in place to enhance the reliability?

Dry gas seals have been used for compressors for many years. The feedback was mixed in its infancy, and there were teething problems. External factors such as the contamination of the sealing gas, insufficient sealing gas pressure and process gas leak onto the seal ring surfaces have been the main reasons for seal degradation.

(2011) Question 5: What are the pros and cons of motor vs. steam turbine drives for hydrotreater and hydrocracker recycle compressors?

The nature of the hydroprocessing unit is such that a wide range of molecular weights are possible for the recycle gas from nitrogen at start-up to hydrogen with increased light ends during normal operation. While the treat gas requirements are pre-determined, quench gas demands vary during normal operation with varying chemical hydrogen uptakes and emergency situations.

(2011) Question 6: Organic chloride in feed streams to hydroprocessing units is becoming more prominent. Chloride measurement is very important to define correct unit metallurgy; however, measurement is difficult. One of the issues related to accurate analysis of the feed is the impact of feed nitrogen and sulfur on chloride measurement. What test methods are you currently using in light of high nitrogen and sulfur in the feed to give accurate chloride results?

For measuring chloride in feed stream, some of our refineries use an instrument based on Monochromatic Wavelength Dispersive X-Ray Fluorescence (MWD XRF), for which nitrogen and sulfur offer no interference. The instrument measures total chloride, whether organic or inorganic. The relevant ASTM method is D7536.

(2011) Question 7: Are there any standard sampling and analytical methods that can be used in the refinery labs to accurately determine the silicon content in the feed to the coker naphtha hydrotreater?

The issue is how to accurately determine the silicon content. Standard Inductively Coupled Plasma (ICP) techniques will give a result that is equal to or greater than the true amount of silicon present depending on if the silicon is in a volatile form (low molecular weight silicones). So, ICP can be used to screen samples and ensure silicon levels are below a desired limit.

(2011) Question 8: In order to minimize fouling of the hydrotreater reactor feed/effluent exchangers, how important is it to have hydrogen gas in the feed side of the exchanger? Is there a minimum gas flow to see the benefit? Does it matter if it is recycling gas or makeup hydrogen?

Pre-mixing hydrogen with feed ahead of the feed/effluent exchangers improves the velocity and increases the shear stresses. This directionally reduces the fouling tendency; as well as, lowering the film thickness and dependent tube wall temperature in the heat exchanger and the charge heater.

(2011) Question 9: What has been your experience with antimony and phosphorous poisoning on hydrotreating catalyst performance? What is the maximum level?

The effects of antimony in oil on hydrotreating catalyst have not been directly studied, but we can infer the likely impacts of antimony from a variety of information sources and past experiences.

(2011) Question 10: When replacing a noble metal catalyst with a base metal catalyst in a two-stage hydrocracking unit configuration, how can you be certain that under a low sulfur, low hydrogen sulfide environment, the second stage catalyst will remain sulfided?

A base metal sulfide catalyst will always have less, or hydrogenation compared to a noble metal catalyst. However, in certain situations where deep hydrogenation is not needed, the base metal sulfide catalyst can provide adequate hydrogenation activity. Operation with a base metal catalyst will be between 10 to 20o F higher than a noble metal catalyst, and this will shift the yield towards more thermally cracked lighter products.

(2011) Question 11: What is the minimum hydrogen sulfide required in the recycle gas for units with low sulfur feed? Do you inject sulfur compounds to maintain a minimum concentration?

It appears that in these processes the catalyst slowly loses its HDS activity. This is due to the transformation of the Molybdenum present as activator, and Nickel/Cobalt present as promoters, from their active sulfide form to the inactive metal state.

(2011) Question 12: Is there any harm adding cracked stocks too quickly after break-in following catalyst activation? What is a typical introduction rate?

On freshly activated catalysts, the surface is relatively clean (free of coke) and therefore is unusually active. This is sometimes referred to as hyperactivity. In order to maximize catalyst stability for good cycle length, it is important that the rate of coke lay down on freshly sulfided catalyst is gradually controlled. Upon completion of metals sulfiding, catalyst hyperactivity exists, but is short lived as feed processing lays initial coke on catalyst. Processing cracked stocks that contain more reactive molecules and coke precursors too early over the hyperactive catalyst can result in operability issues through cracking while accelerating the initial coke lay down on catalyst.

(2011) Question 13: What are your experiences with alternate procedures or additives to speed up the time to hydrocarbon-free a hydrotreater during cool down? What are potential downsides? Qualitatively, did the time savings justify the expense?

We have used a terpene-based product to help free hydrotreater reactor circuits of hydrocarbon in preparation for catalyst change-out. The product was effective for achieving a low level of combustibles in the reactor and in all vessels of the reactor circuit. However, in one instance, the test for entry indicated high benzene levels, and further nitrogen purging was required.

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