| American Fuel & Petrochemical Manufacturers

Question 43: In order to meet RMACT 2 regulations for reducing regenerator vent gas HCl and Total Organic Carbon, some refiners use caustic scrubber vent gas wash tower systems for treating the regenerator vent gas. What has been your experience with respect to corrosion problems? Which equipment (Venturi scrubber, wash tower) and piping have corroded more often? What changes have been made in procedure and/or metallurgy to minimize corrosion?

We have three CCRs with vent gas scrubbers; all are carbon steel, and all have experienced corrosion problems.

Question 42: Are you adding hydroxyl generating compounds (methanol or other alcohols) to the chlorination zone of the continuous catalytic regeneration section of their reforming unit? What are the observed results of this procedure?

Whether or not methanol or another hydroxyl in injected into the oxy-Chlorination zone is based on the design of the regenerator. UOP designed units do not inject hydroxyls into the oxy-Chlorination zone, UOP recommends you contact the process Licensor before making any alternations to the Regeneration Tower flows or controls.

Question 41: What is your best method for detecting nitrogen levels in reformer feeds? How effective is naphtha hydrotreating in reducing nitrogen levels?

Nitrogen in naphtha feedstock can be detected using analyzers based on pyro chemiluminescence or electrochemical measurement. Pyro chemiluminescence-based analyzers appear to be more prevalent in the industry and can detect nitrogen levels over a wide range (from ppb levels to several hundred ppm) in a matter of minutes. ASTM D4629 is a standard test method for trace nitrogen detection in liquids based on pyro chemiluminescence.

Question 40: Are there instances where mercaptan treatment of refinery gasoline or naphtha streams is necessary? What are the applicable treatment methods?

As mercaptans are sulfur-bearing compounds, they are one among numerous target species for sulfur removal from naphtha or gasoline streams to meet reactor feed or finished product sulfur specifications.

Question 39: What are some mitigating strategies for reducing corrosion in the fractionation section of a naphtha or light-ends unit?

The potential problems are most of the time located in the columns overhead where some water may condense locally. Corrosion inhibitor injections are systematically foreseen in strippers' overhead columns.

Question 38: What is your experience with rod baffle exchangers for naphtha hydrotreater or reformer preheaters?

There are a number of vertical RODbaffle® exchangers in ConocoPhillips Reformer preheat service. They have very good heat transfer and excellent reliability.

Question 37: To help manage fouling and pressure drop in a naphtha hydrotreater, do you rely on graded bed technologies or feed filtration (magnetic or other) or both? What is your experience with these options? What other means are being employed?

The countermeasures to pressure drop build-up in naphtha hydrotreaters units obviously depend on the cause of the fouling. The two main causes that we know in Naphtha HDT units of are corrosion particles usually coming from outside the battery limit and gums or coke. Axens addresses those two issues at design stage.

Question 36: What changes have you made to the C5/C6 Isomerization unit to comply with the new benzene regulations; what changes have you made to the refinery operation; and what have been your challenges and successes of implementing the new configuration?

More severe regulation in term of Benzene in the gasoline pool can lead to increase the Benzene content to the C5/C6 isomerization unit. This can happen in two different ways.

Question 35: How far can the hydrogen to hydrocarbon ratios be decrease in gasoline hydrotreating units before experiencing high reactor pressure drops? Please provide some details of your experience with reference to the run length limitations and operating performance.

We have number of naphtha hydrotreatment units in our refineries, some operating with straight-run naphtha as feed and others in mix mode with significant cracked feedstock varying from 10% to 40%, to produce feedstock for catalytic reformers. I suppose, the question here is for hydrotreating units processing cracked components.

Question 34: What is your best practice for minimizing octane losses based on unit operating parameters and/or catalyst types in FCC gasoline post-treat units?

Minimizing octane loss while hydro desulfurizing FCC gasoline implies minimizing olefins saturation with hydrogen. This is all about selecting the right operating conditions (temperature, pressure and H2/HC) so that the hydrodesulfurization reactions are fast enough, but the kinetics of the olefin's saturation reactions remain low.