| American Fuel & Petrochemical Manufacturers

Question 12: What operating strategies do you employ to successfully regenerate catalyst in a continuous catalyst regeneration (CCR) unit with a carbon content in excess of 10 wt%?

The burn zone in a Honeywell UOP Platforming™ CCR Regenerator is designed for operation at 5 wt.% carbon on catalyst or about 5.25 wt.% coke at the design catalyst circulation rate. We find that most units can operate normally at coke levels 40% above the design (about 7.4 wt.% coke) and some at even higher levels of coke.

Question 11: What is your acceptable limit for organic chloride concentration in a naphtha hydrotreater feed? What are the possible consequences if this limit is exceeded?

Chloride in naphtha hydrotreater feed can often lead to fouling and/or corrosion issues in the naphtha hydrotreater heat exchange equipment. Recommendations to keep chloride levels under 0.5 ppm in the feed are typical.

Question 10: What strategies do you employ to meet cycle-length targets in naphtha hydrotreaters that are reaching catalyst activity limits due to capacity increases or feedstock quality decreases?

To increase cycle length on an NHT hydrotreater, the refinery needs to understand the contaminants that the reactor must handle and optimize the bed loading to maximize cycle length, as well as have the ability to handle the contaminant.

Question 9: Describe your experience and application of advanced separation techniques, such as DWCs (dividing-wall columns), to reduce capital investment and operating expense.

At Valero, we actually have several dividing-wall column applications. We have four in aromatics recovery service and one in a sat(saturated)gas plant service. The towers in aromatic service have been in operation between three and six years, and the tower in the sat gas service has been in operation since early 2016. All towers are meeting their design expectations. The dividing -wall towers have several advantages relative to the traditional sequential column designs.

Question 8: Do you have experience starting up an isomerization unit (an alumina chloride catalyst type) without first acidizing the reactor loop? What was the impact on catalyst activity?

Honeywell UOP strongly recommends that acidizing of the reactor circuit should be included in the commissioning and startup of a new grassroots or revamped Penex™ or of Butamer™ units (isomerization units with chlorided alumina catalyst). If not, the consequence can be a significant amount of catalyst deactivation, as well as possible corrosion in the reactor section of the unit. A recent experience in which the customer elected to NOT complete the dry out and acidizing of a new reactor section resulted in an estimated deactivation of 60 to 85% of the new catalyst load.

Question 7: How is propane content in the refrigeration loop optimized against the compressor capacity to minimize contractor temperature? Do you have a good process model to predict the optimum propane content?

There is an optimum propane concentration in the refrigerant that will allow the alkylation unit to operate at a maximum alkylate throughput when the unit is up against limitations of both the compressor and the reaction zone heat removal capability. That optimum concentration of propane will vary from unit to unit and can be different seasonally. It can also be different from night to day or if exchangers are fouled, etc.

Question 6: What is your experience with having a vent depropanizer off-gas unit in order to manage tower pressure, and what might be the cause of and solution to the problem?

The typical and probably most obvious driver for the need to vent from a depropanizer column is the presence of non-condensable gases. Most commonly, this is ethane and ethylene that come in with the feed.

Question 5: What are the typical dispositions of coker olefins, light coker naphtha, and heavy coker naphtha in refineries that you employ? How are the sulfur contaminants, such as dimethyl sulfide and dimethyl disulfide, best removed from these streams?

This question asks about the fate of coker olefins and coker naphthas. What we are looking at here are the three coker product streams, which include coker LPGs (liquefied petroleum gas), your C3s(propane/propylenes) and C4s (butane and butylenes), and light and heavy coker naphthas, which must be further processed before they can be blended or sold into the gasoline pool. Coker products are really a challenging feedstock.

Question 4: The economic benefit for propylene and amylene alkylation is improving. What considerations do you use in the feed pretreatment and alkylation unit operations before increasing these feeds?

Increased processing of propylene and amylene feedstocks in alkylation (alky) units does bring challenges, but most will depend on the configuration of the existing unit and whether any of these feedstocks have been processed before.

Question 3: What process safety PSM) factors do you consider when contemplating a reformer unit rate increase?

Any change should be handled through the MOC (management of change) process, according to OSHA 1910.119: Process Safety Management of Highly Hazardous Chemicals. This standard includes requirements for preventing or minimizing the consequences of catastrophic releases that may result in toxic, fire, or explosion hazards.