| American Fuel & Petrochemical Manufacturers

Question 24: How many refiners import and/or purchase gasoil feed for a hydroprocessing unit? What are common issues associated with imported or purchased gasoil feeds? Are there specific characteristics to target and / or avoid? Are there best practices for minimizing negative impacts to unit operations / reliability? How are supply limitations managed?

Key characteristics of imported feed like end point, sulfur, nitrogen, chlorides and carbon residue can be controlled by establishing allowed specifications. But other characteristics may be hard to control.

Question 23: What are the sources of silicon that can impact a hydrotreater? How does silicon affect hydrotreater operations? What are your best practices for managing / mitigating silicon poisoning?

One source of silicon is antifoam chemistries. These may be introduced into HDS feeds via use in the Coker process within the refinery or via use in production upstream of the refinery.

Question 22: Can you elaborate on the benefits, drawbacks, and trade-offs of liquid phase vs. gas phase catalyst activation in a hydrocracking unit? Is there an activity or yield difference of liquid phase or gas phase activation of 2nd stage catalyst in a 2-stage hydrocracking unit? Consider both catalyst formulation and operational factors (MPT, excursion risk, etc.)

Activation (or sulfiding) of hydrotreating and hydrocracking catalysts can be done either ex-situ or in-situ. In both methods, the objective is to convert all the catalyst’s metal oxide sites to active metal sulfides.

Question 21: What are your important considerations for water washing with respect to: 1) Intermittent injection a. Process temperature of injection b. Duration of injection c. Frequency - triggers to begin d. How frequently before making it continuously? 2) Water Quality: a. pH range b. Oxygen c. Total Suspended solids d. Total dissolved solids e. Recirculation vs. make-up f. Other

Hotter temperatures typically will increase in the need for better designed injection systems. The injection mix point needs to be designed to contact and scrub the vapor well, with adequate dilution of water, with metallurgy at the injection point selected to handle the lower pH of the droplets.

Question 20: What considerations do you give to co-processing or block mode operations with renewables in an existing hydroprocessing unit?

In all scenarios, a refiner must consider their RFS obligations, potential biodiesel tax incentives, biodiesel merchant market, refiner’s existing hydrotreating units’ utilization rates, capabilities, and designs, renewable feedstock types, availability, price, and pre-treatment requirements, and product specifications and storage constraints.

Question 19: What considerations do you use for designing a hydrocracking reactor? What criteria do you use to determine number of beds, diameter, and beds’ lengths?

Hydrocracking reactor design is a proprietary technology with each licensor having their own specific design practice based on operating experience, catalyst technology, and engineering expertise. It is not the purpose of this forum to reveal proprietary technology, but to improve refiners’ operations through shared experience.

Question 18: Vacuum Gas Oil (VGO) Hydrotreaters are being pushed to process heavier feeds while maximizing Fluidized Catalytic Cracking Unit (FCCU) performance while meeting Tier III gasoline specifications. How are you balancing increased severity and cycle length? What considerations do you give to feed quality and upstream unit operations?

The FCC unit has long been the workhorse in the refinery to achieve relatively low-cost conversion of heavy crude components (VGO, HCGO and some atmospheric residue) into gasoline, butenes for high-octane alkylate production, propylene and LCO diesel blend components.

Question 17: Where do your route your disulfide oil from caustic treatment? If disulfide oil, that may contain caustic or other contaminants, is routed to a hydrotreater, what are preferred methods for treating it to avoid fouling exchangers, furnaces and catalyst?

Disulfide oil is gravity settled out of the regenerated caustic in a settler vessel. A slip stream of cold Naphtha or #1 fuel oil is injected and used to help provide a larger volume of hydrocarbon to dissolve the disulfides and aid in separation (Sponge Oil).

Question 16: How are you performing in-situ sulfiding for hydroprocessing catalysts protecting your waste water units from water soluble organic chemicals and their fuel gas system from non-decomposed mercaptans?

The exact temperature needed to achieve complete decomposition is dependent on the pressure, the catalyst type, and the space velocity in the reactor.

Question 15: As hydrotreating catalyst development continues with the emphasis on activity and saturation, how has this changed optimization strategies for the entire hydrocracker?

Advances in hydrotreating catalyst technology continue to produce steadily increasing performance for hydrocracking pretreat service. These improvements result in increased HDN and aromatics saturation performance which are key to optimizing overall hydrocracker performance.