There have been many inquiries into shifting naphtha hydrocrackers to distillate mode over the last couple of years. The optimal solution is dependent on feed qualities, hydrocracker configuration, distillation, and gas recovery hardware, as well as the value of volume expansion across the hydrocracker.

Catalyst typically deactivates due to an accumulation of contaminants and due to process upset coke formation. It also deactivates due to what I will refer to as routine coke formation.

Generally, a break-in period is very dependent upon the catalyst type in the intended service; so, it changes a little with each unit. To reiterate again, it is important to have a good relationship with your catalyst vendor. Ask specifically what the vendor wants to see in terms of unit start-up procedures and feed specs.

The topic of the causes of high-pressure drop was discussed in the 2007 Q&A, so you may want to refer to that transcript for additional information. At Chevron, we had a string of 13 reactor ΔP (pressure differential) incidents between 2007 and 2011. Ten of these occurred in lower reactor beds with only three of them being classic top bed ΔP incidents.

If you take a look at the molecular structure and properties of hydrocarbons in the C14 series, you will notice that the n-paraffins have the worst cold flow properties.

For grassroots design, developing the project scope and your considerations can actually be a lot easier when starting with an empty plot space. However, for existing hydrotreaters, there are a lot of significant considerations that need to be reviewed if you are considering moving to mild hydrocracking operation, as it is usually not just a drop-in catalytic solution.

The primary impacts of loss of hydrogen circulation or flow. If you have a once-through unit are obviously loss of catalyst activity and increased reactor pressure drop. In some cases, you do not notice that these are occurring; so, at the start-of-run, you have excess void space and excess activity in the reactor.

This question is directed more at the bitumen-derived type of crudes. I call all of them mined crudes from tar sand sources. We process a lot of these materials at our two refineries. The crude goes under the name of Western Canadian Select, which oftentimes is not very select.

The shale crudes in question are highly paraffinic, low sulfur, low nitrogen, and low in conventional contaminants. However, we do see some trace contaminants coming in from some of the fracking and completion chemicals. These crudes have a low resid content, which impacts the bottom of the barrel.

The increased desulfurization of distillate fuels removes sulfur nitrogen and aromatics, which are components favorable for lubricity properties. The recent market conditions have led most refiners to not only produce ULSD, but also ULSK (ultra-low sulfur kerosene), in order to maximize distillate production.