Q&A

(2012) Question 96: What is the CO boiler start-up and shutdown sequence with respect to the FCCU start-up and shutdown timing? What are the reasons for this sequence?

As I mentioned briefly in an earlier question, most of our FCCs with CO boilers start-up with the CO boilers bypassed. If we run partial-burn on any of these FCCs, we tend to start-up in full-burn at reduced rates. Once the feed is in the unit and considered stable, most sites will cut into their CO boiler with the process flow.

(2012) Question 97: What equipment do you employ to help eliminate ESP hopper and downcomer plugging with catalyst fines? What additional operating practices are used? What type of level detectors are in use on the ESP hoppers and/or catalyst storage silos? Are there any new level detection technologies that could be applied, perhaps from coke drum measurement detectors?

Our main problem with the ESP is fines accumulation in both the ESP hoppers and the transfer line from the hoppers to the fine's storage bin. We have incorporated some design improvements that have helped us minimize, but not completely eliminate, the main problems of condensation in the system and plugging.

(2012) Question 98: What is your experience with the use of ammonia or steam in the FCC flue gas line in order to improve the operation of the ESP? Please comment on system configuration and operational issues

We have extensive experience with the use of ammonia in the FCC flue gas line in order to improve the conductivity of the particles and improve the operation of the ESP. We inject ammonia at the target level of 10 parts per million or less.

(2012) Question 99: Have refineries experienced an increase in particulate emissions in the regenerator flue gas caused by oxygen enrichment of air to the regenerator?

We have quite a few refineries that use oxygen enrichment. One of them uses it in very high concentration. None of the sites – and I spoke with them specifically about this – say that they have seen an increase in particulate emissions as a result of increasing their oxygen enrichment.

(2012) Question 5: Reforming of feedstocks from ‘tight oil’ crudes offers unique challenges such as low naphthene and aromatic (N+A) content, lighter feed, and differences in coke yield.What are refiners doing to address these challenges and generate opportunities for these new crudes?

From a project standpoint, there have been inquiries related to tight oil and proposals generated, but not a significant number of actual projects realized for revamping units. It appears that most refiners are able to accommodate the tight oil in their existing units. Some of this accommodation has to do with the naphtha area capacity issues in the U.S. of which I am sure everyone is aware.

(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.

(2012) Question 16: What is the commercial experience on the use of H2 membranes in hydrotreaters or hydrocrackers for H2 recovery? What is a reasonable membrane life given the sensitivity to fouling and temperature changes?

At the Denver Refinery, we have a few hydrogen separation membranes. We call them our hydrogen purification unit. Our #3 HDS, which is currently our ULSD unit, was previously a gas oil hydrotreater until we revamped it in 2006. So, the HPUs (hydrogen purification units) were in consistent service from 1990 to 2006.

(2012) Question 17: Now that natural gas prices are low in North America, what options are available to increase refinery volume gain and product quality by exploiting low-cost hydrogen? Is the low hydrogen production cost impacting the economics between the selection of coking or hydrocracking?

There were a number of questions this year that requested information about how to effectively utilize low-cost hydrogen to increase refinery volume yields.

(2012) Question 18: What are the economic incentives to justify upgrading reactor internals? What techniques have been utilized to assess the performance of existing reactor internals?

The primary incentive is catalyst life and the ability to meet turnaround intervals. Gas and liquid distribution improvement results in increased catalyst performance and potentially longer catalyst life. Reactor internal upgrades may consist of quench decks, mixing chambers, and improved liquid distributor trays.

(2012) Question 19: Since API-932 (Waterwash Best Practices) was published, what has been the impact on reactor effluent air cooler washwater system design and reliability? Are there any active or ongoing studies to improve waterwash systems, in addition to API-932?

The question of issues associated with waterwash has been discussed since the API-932 was issued. This first slide gives a little chronology of some of the documents.

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