Q&A

(2012) Question 26: What catalyst and metallurgy design considerations are important when evaluating the co-processing of highly acidic renewable distillates? What can be done to mitigate carbon monoxide formation?

Acidity of renewable distillates can be intrinsic of the material (free acids of the vegetable oil) or generated during its conversion in the hydrotreating unit. Typically, free acids in vegetable oil amount to about 5%. This means that crude vegetable oil has a TAN number around 7, which requires special metallurgy for the pipelines to the feed drum.

(2012) Question 27: What are the Best Practices around minimizing risk of catalyst or equipment damage during turndown operation of a steam methane reformer hydrogen plant?

Depending on the feedstock and configuration, most units operate with an S/C ratio between 3 and 7. However, during a turndown situation, the operator should target a higher S/C ratio and run at least 75% of the design steam rate. Doing so helps maintain adequate mass flux in the tubes to achieve good distribution, avoid hot tubes, and minimize catalyst damage.

(2011) Question 1: Do any of you place an alarm or upper limit on the operating pressure drop (dP) through a hydrotreater reactor circuit (preheat exchangers to High Pressure Separator)? If yes, what is the basis for the maximum dP?

One of our refineries has developed limits for pressure drop through the reactor circuit. The maximum allowable pressure drop is determined by the difference between the upstream reactor or heat exchanger design pressure and the set pressure of the relief valve on the high-pressure separator. The purpose of the alarm is to ensure that the upstream vessel’s design pressure will not be exceeded before the pressure at the downstream relief valve reaches the set pressure.

(2011) Question 2: In hydrocrackers, how are your sampling systems designed to safely obtain inter-reactor / reactor effluent samples?

Inter-reactor sampling can be important for monitoring catalyst performance, troubleshooting, and measuring yields. In a hydrocracker, such a sampling system allows measurement of nitrogen slip from the pre-treat section into the hydrocracking stage.

(2011) Question 3: How are you managing your units to mitigate risk of HTHA (High Temperature Hydrogen Attack)? What are monitoring best practices? Should we be concerned about short term operating periods such as startup, shutdown, hot stripping, etc.?

HTHA is a form of degradation of metal caused by hydrogen reacting with carbon in the metal to form methane in a high temperature environment, typically above 400 deg F and 50 psia H2 partial pressure.

(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.

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