FCC profitability assessment via 
advanced modelling

Process and computational fluid dynamic modelling were applied to validate the technology used in an FCC unit revamp at Shell’s Puget Sound refinery.

Shell Global Solutions (US) Inc
CHARLES BURTON, Motiva Refining
STEVE NELSON, Shell Oil Products US

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Article Summary

The FCC unit at Puget Sound was originally installed in 1958. Over the intervening years, the unit was modified several times. The last revamp in 1999 installed a new external riser as well as the current reactor vessel and with the unit configured as a two-vessel side-by-side FCC unit with an external riser. The reactor vessel contained the reactor cyclones with a stripper incorporated within the bottom section of the reactor vessel. The basic layout of the FCC unit is illustrated in the process flow diagram used in the project scope (see Figure 1).

During the refinery’s 2009 turnaround, Shell determined the unit’s riser refractory to be at end of life and in need of renewal. Replacing the refractory would have been a major effort, potentially extending the next turnaround in 2014. Therefore, the company decided that replacement would be a more cost-effective unit upgrade and life extension strategy.

Technical review of the riser determined that the riser residence time was too short for the current demand. Replacement of the riser simply to increase riser residence time would not have met the required return on investment criteria. However, once the company decided to replace the riser refractory, the incremental engineering and fabrication costs were low enough to justify the increase in riser residence time.

Likewise, the as-found condition of the stripper in the 2009 inspection indicated that replacement would be cost effective as an alternative to the required repairs that would have had to be scheduled for the 2014 turnaround. For example, the existing stripper was a disk and donut design, which was prone to flooding at high catalyst circulation rates. As with the riser, the incremental cost of replacing the stripper with a new Shell design was justified when compared to stripper repair and refurbishment.

FCC unit turnaround Scope and incentives
Project premise: driver for change

The 2009 equipment inspection revealed the riser refractory to be at end of life condition and anticipated repairs would result in a significant extension to the refinery’s planned 2014 turnaround duration. Similarly, the amount of repair to the stripper disk and donuts, combined with the health, safety and environmental risks of extremely tight working conditions, could also not be completed within the planned turnaround window. Thus, replacement of the riser and disk and donut stripper became the preferred and more cost effective alternative to repair. Once the decision to replace the riser and stripper was made, the incremental cost of the upgrade versus an in-kind replacement was easily justified based on the incremental margin improvement.

Originally, an expansion joint was not included as part of the regenerated catalyst standpipe design. Increasing the riser volume increased system stiffness. The riser upgrade resulted in system rigidity under start-up and shutdown conditions, which contributed to both high regenerator nozzle stresses and regenerated catalyst slide valve sticking. As a result, an expansion joint was added above the regenerated catalyst slide valve. At the onset of the revamp scope definition, installation of an expansion joint was in the project scope for the spent catalyst standpipe as well. However, after applying value engineering practices, it was removed with just minor regenerator nozzle reinforcement, resulting in significant savings. The regenerated catalyst slide valve had a history of sticking, identified as an on-going reliability threat for the unit, and therefore was replaced with a new valve incorporating the best of Shell’s current FCC technology design elements.

The company justified the incremental cost of the riser and stripper replacement partially on the basis of the anticipated margin improvement from the unit revamp. Since the riser and stripper replacement were primarily justified to minimise turnaround duration, the incremental cost for upgrading this equipment was relatively small, amounting to some additional engineering and fabrication cost.
Project planning and execution
The project was kicked off in early 2011 and involved Puget Sound refinery staff and Shell Global Solutions jointly working through the options evaluation, economic reviews, and preliminary project scoping. Shell utilised a third party firm for detailed engineering and project management. Concurrently, the same firm managed a parallel upgrade project for the FCC unit’s instrumented protective function (IPF). A fabrication contractor was then brought in as equipment fabricator, with field construction completed by a construction contractor as part of the overall turnaround. Part of the project’s execution strategy was to engage the construction contractor during revamp scope design to ensure planning for constructability and sequencing of delivery and lifting within the overall turnaround schedule.

Overall, the project was well developed and executed. All potential challenging issues were quickly identified and resolved with minimal impact to the overall project or the turnaround. An outstanding team effort was involved in the safe and successful completion of the project.

Puget Sound FCC unit today
Today, Puget Sound’s FCC unit operates on average at rates up to 52000 b/d, processing vacuum gasoil and unhydrotreated heavy coker gasoil. The unit includes Shell’s technology designs installed during the latest revamp in March and April of 2014. The present 
unit configuration following the revamp includes the following plant upgrades (see Figure 2):
• New riser of larger diameter, new HIB rings to inner lining and increased residence time
• New J-Bend
• New feed nozzles including associated piping
• New stripper, lengthened and upgraded from disk and donuts to Shell’s PentaFlow baffle design
• New regenerated catalyst slide valve incorporating current best practice design
• Regenerator standpipe expansion bellows to alleviate stresses
• Upgraded IPF system with new instrumentation and logic system
• Completion of new DCS cutovers.

The revamp was successfully completed on time, within the turnaround window and the planned budget. Post turnaround, the unit has operated very well, realising an estimated benefit matching the expected cost versus forecasted gains as the business basis for the revamp.

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