Q&A

(2015) Question 38: What are your concerns with processing FCC heavy cycle oil or slurry in a hydrocracker unit?

In most of our experiences, I think that FCC heavy cycle oil and slurry oil are just nasty. [Laughter] Basically, the heavy cycle oils are known to be very challenging when run in a hydrocracker due to the high concentrations of coke and HPNA (heavy polynuclear aromatics) precursors.

(2015) Question 39: In terms of hydrocracking, what different definitions of conversion do you use?

Fundamentally, conversion is probably the most common operating target used for hydrocracking units. Conversion provides us with a measure of the amount of reaction or the amount of work that is accomplished in the unit. The simplest definition for conversion is typically this equation for gross conversion: a hundred times the fresh feed minus the unconverted oil, divided by the fresh feed; unconverted oil being the recovered fractionator bottoms.

(2015) Question 40: What has been your experience regarding time required for hydrocracking operations to recover from temporary poisoning by organic nitrogen in the feed? What operational changes can be made to reduce the chance of permanent deactivation?

It can be a short duration, one to two days, or potentially longer, 21 to 30 days, depending on the response to the events and dependent upon the amount of higher severity feed, higher nitrogen, and higher aromatic content feed. It could be a shorter duration if quickly caught and corrected.

(2015) Question 41: How do you manage operating flexibility to maximize profits in a changing margin environment during a hydrocracker cycle?

Frequently, market conditions will reward the refineries that have a little flexibility in shifting their product yields among conversion units. We try to do that where that flexibility exists. For a hydrocracker, a primary knob is just overall conversion. Decreasing conversion will enhance distillate yield, increasing conversion, gasoline yield.

(2015) Question 42: Is the investment justified to convert an older hydrogen production unit from a solvent CO2 removal system to a pressure swing adsorption (PSA) system?

My analysis suggests that this kind of a modification is not economically justified for the small solvent system hydrogen production unit operating at the Flint Hills Resources Pine Bend Refinery. While it is true that a PSA unit is more efficient than a solvent unit, the capital required to convert between the two is too high.

(2015) Question 43: For PSA units, what are the typical inspection techniques, frequency of inspections, and issues discovered? What are the criteria for retiring an adsorber?

At Flint Hills Resources Pine Bend Refinery, external ultrasonic testing is performed on areas of concern (welds, heat-affected zones, attachments, or identified stress risers) every five years. To date, no areas of concern have been identified in the PSA vessel inventory.

(2015) Question 44: What are your Best Practices for co-processing streams in hydrotreating units?

The first one is our hydrocracker where we do both straight-run and coker gas oil. What we watch for there are changes in the feed composition due to the cyclical nature of the coker and the affects that we see in the hydrocracker reactor in the fractionation section because of that.

(2015) Question 45: What are the recent improvements in hydroprocessing units’ advanced process control? What is your experience with their reliability?

As we have all probably experienced, efficient and reliable unit operation can benefit significantly from the application of advanced process control, or APC. For example, most hydrocracking units have implemented some level of advanced control to stabilize fractionation operation or control conversion. Advanced control projects typically pay off very quickly. In the past, the industry has typically focused on implementing advanced process control to optimize one aspect of a processed unit.

(2015) Question 46: What are the mechanical integrity implications for reactor effluent air REAC) after experiencing high-temperature exposure during emergency shutdowns or trips?

During emergency feed removal or partial feed loss of a hydroprocessing unit, the loss of feed oil as a heat sink through the feed/effluent exchangers can elevate temperatures downstream. Expected temperatures can be estimated through process modelling of normal maximum reactor effluent flow continuing at maximum reactor outlet temperature without feed flow through the reactor effluent cooling train.

(2015) Question 47: How does a recycle compressor driver type (steam turbine versus electric motor) affect compressor availability in hydroprocessing units? How reliable are variable speed drives?

Our experience at Valero has been that turbines are more reliable than electric motors. For electric motors, the failures are not caused by the motor itself, but rather by the availability of electric power. Power failures tend to be the most common concern.

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

Q&A