Q&A

(2013) Question 50: What are the technology evaluations and engineering studies required for revamping a diesel hydrotreating unit to substantially increase throughput?

In any major revamp of throughput for a DHT (distillate hydrotreater), establishing a realistic design basis and engineering certainly never really exists. The idea is to look not just to the point but at deviations and feedstock properties, expected changes in compositions, and past history of contaminants.

(2013) Question 51: For hydroprocessing reactor modifications that involve the addition or removal of distribution trays and flexible thermocouples, what is your Best Practice for welding support rings or support lugs on a reactor wall? What is your Best Practice for removal of these items when they are no longer required?

When you are trying to remove the attachments from the reactor, do not touch them unless it interferes with your process flow, catalyst loading, or internal installation or access. When the rings are welded to the support rigs, remove the rings and leave the lugs in its place.

(2013) Question 52: What is the configuration of thermocouples that can be used to effectively monitor radial temperature differences, and what is the acceptable radial temperature spread in hydrotreaters/hydrocrackers?

The UOP bed thermometry consists of a stab-in type of assembly with three thermocouples on top of the bed. Typically, a multipoint thermometer is provided in the case of the first bed of a hydrotreating unit and if the bed length is more than 11 feet for a hydrocracking bed. At the bottom of the catalyst bed, industry-standard flexible-type multipoint thermocouples are specified.

(2013) Question 53: With respect to hydrotreating, what is the typical (CO + CO2) impurity in hydrogen produced from pressure swing adsorption (PSA): 10 ppm or 50 ppm? What problems can be expected if the (CO + CO2) exceed this value? If the hydrotreaters can handle higher than (CO + CO2), is it possible to run the PSAs harder and produce more hydrogen?

UOP has designed around 1000 PSA units. For most of the refinery applications, the impurity limit has been set to less than 10 ppm. The table shows a comparison between specs when relaxed from 10 to 100 ppm. H2 recovery was also checked when specs were tightened from 10 ppm to 1 ppm.

(2013) Question 77: What are the consequences associated with continuing to operate the FCC without main fractionator bottoms cooling circulation?

We considered this question as three parts: What is the action to follow in the event of a loss of bottoms’ cooling? What is the consequence if you lose the net slurry product? What are the operational possibilities if you have a well-planned outage of the slurry circuit? In situations one and two where you have lost circulation or you have lost the net bottoms’ product in the system here, we expect that you would shut down the unit consistent with your licensure’s emergency shutdown procedures.

(2013) Question 78: What procedures (maintenance and operational) are being used to minimize risk when swinging the blind between the reactor/main fractionator?

There are two scenarios to consider: shutdown and startup. I will address the shutdown scenario first. For the shutdown scenario, catalyst is de-inventoried from the reactor and regenerator systems, and the main column and reactor are cooled down to 350°F. There are certain operational conditions that must be satisfied before the blind is installed.

(2013) Question 79: How do you mitigate the risk of falling coke deposits from the reactor plenum chamber and vapor line during initial vessel entry?

We have not had the experience of falling coke deposits on vessel entry. We usually experience difficulty in removing the coke deposits, and we do this by mechanical means. Prior to entry into the reactor, a visual inspection is made from the manway. It is typical to see stalactites from the reactor plenum.

(2013) Question 80: We have coke deposits in the plenum chamber and vapor line and are concerned the deposits may spall off or ignite during refractory dryout. What precautions should be taken to avoid re-igniting these coke deposits during the dryout?

We prevent hot air from entering into the reactor system during the regenerator dryout. Subsequently, we will use initial catalyst circulation for the reactor side dryout. Prior to lighting the DFAH (direct fire air heater) for the regenerator refractory dryout, we will introduce dry steam into the reactor, feed distributors, reactor riser, reactor dome, and stripper section.

(2013) Question 81: How do CO (carbon monoxide) and NOx (nitrogen oxide) emissions change when you operate at low regenerator temperatures? What can be done to mitigate any increases?

I will initially address this question from a CO standpoint and then discuss the NOx. CO emissions typically increase if the regenerator falls below a certain temperature threshold. That temperature threshold will vary based on your regenerator configuration and definitely on the type of air distribution.

(2013) Question 82: For those operating units with electrostatic precipitators (ESPs), share your experience with using SOx (sulfur oxide) reduction additives and their impact on: 1) ESP performance, 2) stack opacity, and 3) filterable solids mass.

We have two ESPs in our system. One of them is on a unit currently using less than 2.0% of SOx additive. We have not seen any impact at all on performance, opacity, or filterable solids. The other ESP went through a retrofit within the past four years, going from a smaller, older version of an ESP to a larger ESP with more modern technology.

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