Q&A

(2012) Question 6: Following an emergency shutdown that includes the loss of the recycle gas compressor, is it possible to quantify the effect on catalyst deactivation? What are the Best Practices to minimize catalyst deactivation?

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.

(2012) Question 7: What must a refiner consider when evaluating mild hydrocracking) as a way of increasing diesel production in his/her gas oil hydrotreater?

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.

(2012) Question 8: How do you improve cold flow properties in a hydrocracker?

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.

(2012) Question 9: What do the possible causes of high pressure drop in lower beds of HT (hydrotreater) and HC (hydrocracker) units? What techniques are used to diagnose the causes prior to shut down? Are there any mitigation techniques or strategies to extend the cycle?

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.

(2012) Question 10: Does hydrotreated product recycle count the same as fresh virgin feed for the catalyst break-in period?

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.

(2012) Question 11: How do you set your maximum endpoint targets (short residue, coker, and FCC) for a two-stage mixed feed HCU operating in distillate mode? What is the impact on catalyst life?

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.

(2012) Question 12: For units originally designed as naphtha selective HCUs, what are the considerations for shifting selectivity to distillate production?

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.

(2012) Question 13: What equipment size limitations set the maximum capacity for a single-train, high pressure, heavy feed hydro-conversion unit (HCU ebullated-bed resid)? What are the other considerations?

With an ebullating-bed reactor, the primary throughput limit is set by the superficial velocity, which is a function of reactor diameter and throughput. The superficial velocity is what determines the ability to separate gas from liquid going to the recycle pump.

(2012) Question 14: What is cycle life limiting factors in low pressure jet/kero hydrotreaters?

Factors limiting cycle life in low pressure kero/jet hydrotreaters are mainly related to product quality specifications. In particular, specifications related to aromatic saturation such as smoke point and color.

(2012) Question 15: What can be done to mitigate foaming and emulsion formation in our hydrotreater high pressure separator? Is there any favorable experience with injection of antifoam/chemical emulsion breaker?

We are starting to hear about more foaming problems, particularly with some of the unconventional or shale crudes being processed, and there are a few other instances.

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

Q&A