Q&A

(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.

(2015) Question 48: What is your experience bringing hydrocracking catalyst online without ammonia attenuation? Are there alternative methods or technologies to temper catalyst activity without adding ammonia?

Hydrocracking catalyst needs to be passivated during sulfiding to avoid potential temperature runaway as temperatures are increased to complete the sulfiding process. In our experience, there are four different ways that we attenuate the catalyst activity. The first is to inject ammonia prior to the high temperature sulfiding to passivate the catalyst.

(2015) Question 49: Each hydroprocessing unit has an optimum strategy for full load-catalyst replacement: oxidized versus presulfided. How does the strategy change for a partial reload (e.g., top-bed skim or replacement)? Are there other situations when pre-activation is justified?

Use of either oxidized or presulfided catalysts can work fine. It depends on safety approach, cost allowance, time goals, and handling the processing preference. The main point is safely carrying out this skimming operation, whether or not it is oxidized catalyst or presulfided catalyst.

(2015) Question 50: How is your company planning to meet Tier 3 gasoline regulations?

Currently, our gasoline runs at 12 ppm sulfur. There are two sour components: our LSR (light straight-run) and butane. Some approaches we are contemplating for compliance are hydrotreating the LSR, reducing the sulfur via dilution, or restarting an out-of-service Merox unit.

(2015) Question 51: What is your best method for monitoring salt level in a diesel salt dryer? What are your current guidelines for salt usage and capacity? What are your best practices for loading and monitoring salt dryer performance?

We prefer not to use salt dryers in new ULSD designs. In recent ULSD designs, we will put in a vacuum dryer, or we will re-boil the stripper to meet the low water specs. If there are less stringent water specs, using a coalescer can be sufficient. One of our most recent new units will have a coalescer followed by a vacuum dryer.

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