Q&A

(2012) Question 20: What is the industry experience with managing cracked feedstocks to avoid hydrotreater problems such as fouling, and pressure drop?

Some of the mitigation options can be summarized in four areas. The first is feed logistics. We would say that if you are going to handle this, you need to do as much direct feeding as possible.

(2012) Question 21: High pressure strippers are an option for controlling VOCs in process condensate and managing export steam quality in a steam methane reformer hydrogen plant. What types of pH controls are being used?

Most hydrogen plants take the process condensate, send it to a deaerator to clean it up, and then reuse that condensate while mixing it with some boiler feedwater internally. There are configurations that have high pressure strippers where they will bring in some steam and do some initial stripping.

(2012) Question 22: What preventative maintenance program is applied to safety instrumented systems on a steam methane reformer that are Safety Integrity Level (SIL) rated?

Safety instrumented systems (SIS), as defined by ANSI/ISA-84.00.01-2004 Part 1(IEC-61511-1 Mod), are required to have components functionally tested and/or replaced/ refurbished under preventative maintenance (PM) to provide the reliability required to have a Safety Integrity Level (SIL) rating. SIL-rated safety systems are often required when a greater degree of protection layers is required then that offered by standard design.

(2012) Question 23: What are some options for increasing the cetane index (CI) of diesel to more easily meet export market requirements?

Cetane improvement chemistry mechanisms available to us are aromatic saturation and naphthenic ring opening (hydrocracking), both of which allow us to further take advantage of low-cost hydrogen to provide cetane upgrades and liquid volume gains.

(2012) Question 24: Given the potential consequences of back flow in high pressure hydroprocessing services, such as furnace tube rupture and pump shutdown, what layers of protection are being employed to reduce risk?

Our layers of protection are very similar here in that we have trip valves activated by SIL-rated instruments and which are only SIL-rated as required. And of course, we have basic process controls and critical alarm systems. In some, but not all, cases, we do have check valves downstream of our furnaces. That is not a standard at all our sites. However, on some sites, we are consistent about having check valves downstream of our furnaces.

(2012) Question 25: What is your philosophy for mitigating fouling and corrosion in reactor effluent cooler systems in hydrotreater or hydrocracker units during a short-term washwater pump failure scenario? How much time is allowed before initiating a unit shutdown?

Chevron developed a rough set of internal guidelines that determine the allowable time to run without water injection. The guidelines are based upon ammonium bisulfide (NH4HS) concentration. For units that run at what we call low severity, which is zero to 3% NH4HS, we will allow a couple of days of operation without water injection. As the normal NH4HS concentration of the operating unit sour water increases, we allow progressively less time to run without water injection.

(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.

Question 28: What is the panel's experience in block mode operating between VGO and diesel modes? What is the frequency of change of mode and do they see any impact on catalyst activity after each switch?

While Suncor Energy, Inc. does not have any hydroprocessing units designed to routinely operate in block mode between VGO and diesel, at our Denver Refinery we have operated our ULSD unit in AGO/VGO service and routinely operate our gas oil unit in ULSD service for various reasons.

(2012) Question 29: How many refiners are using Layers of Protection Analysis (LOPA) in their Process Hazard Analysis (PHA) studies? How do they quantify the frequency and consequences of initiating events?

Phillips 66 has used LOPA since 2006 when we do our PHA studies. We apply it to the most severe events and use a scale of 1 to 5 for severity. So, if there is a Consequence 4 or 5, then we will apply LOPA to that event. Generally, those are the scenarios with a loss of containment component.

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