Q&A

(2012) Question 50: How do you monitor the integrity of internals, and how do you determine when to replace reforming unit reactor center screens? What is the typical life of the center screens, and when are repairs considered excessive?

Typically, we have seen internals last between 15 and 20 years, if not longer. At any point, it becomes a value judgment between the number of repairs you have made, if any, and the potential outcome if the internals do fail.

(2012) Question 51: What is the panel’s experience with recycle gas moisture analyzers?

Phillips 66 has had experience with the Ametek and Panametrics moisture analyzers. Weare talking about moisture in the reformer recycle hydrogen, so we are looking for 10 ppm to 50 ppm with varying success. I do not think we could say that one is a lot better than the other. The Ametek 5000 was designed for that application.

(2012) Question 52: What is your recommended method for mitigating fouling in reforming unit recycle compressors? Has any technique proven successful? Is anyone using reformate to clean the compressor online?

The best method for reducing fouling in the compressor is to take the nitrogen out of the feed. In Valero, we have recently reviewed our naphtha hydrotreater performance. In a lot of cases, we found that the naphtha hydrotreaters can actually be pressure drop-limited versus activity-limited.

(2012) Question 53: What is the panel’s experience with addressing reforming unit stabilizer salting?

I actually have three examples that all apply to a reformer stabilizer. The first slide shows what we call our hot wash. By that, I mean we do not lower the temperatures. We will keep the bottoms re-boil temp in the 440°F to 480°F range. We then have two options on this hot wash. If we just see a high differential pressure on the overhead cooler, then we will put the water in front of that air cooler.

(2012) Question 54: Does the panel have experience chemically cleaning their reforming unit reactor circuit to minimize the lower explosive limit (LEL) when opening up equipment to the atmosphere in an effort to comply with environmental regulation? If so, is the chemical compatible with the catalyst?

HollyFrontier does not have experience using a chemical in this case. Our normal procedure involves coke burning prior to opening the reactor, and there has not been a problem with LEL in the system after that.

(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.

(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.

Find the answer to your technical question in AFPM's extensive Q&A database.

Q&A