Impact of bitumen feeds 
on the FCCU: part II

Refinery configuration optimisation through LP modelling identifies attractive investments for processing Western Canadian Select. These investments involve 
FCC, VGO hydrotreating or VGO hydrocracking

Keith A Couch, James P Glavin and Aaron O Johnson

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Article Summary

Optimum processing of bitumen-derived crudes requires the refiner to make significant investments to reject additional contaminant carbon and metals, convert extra volumes of vacuum gas oil (VGO), increase the hydrogen content of the FCC feedstock and ensure FCC products meet off-take specifications.

To evaluate the investment options, a refinery linear programming (LP) model was constructed based on a typical North American Gulf Coast deep conversion refinery configured to achieve current mandates required to produce ULSD (15 ppmw maximum) and Tier II gasoline (30 ppmw maximum) with a benzene content of 0.62 vol% maximum (Figure 1). The feedstock costs and product values were based on data published by Purvin & Gertz, CMAI and the US Energy Information Administration (EIA) in September 2006.

The base case crude slate was selected to closely match the US average sulphur content of 1.4 wt% and API gravity of 30.5°, as calculated using data from the EIA. Based on these criteria, a crude oil blend of 50/50 vol% West Texas Intermediate (WTI) and Arab Medium was used. For the study, the following process assumptions were considered:
- Crude rate to the refinery was fixed at a maximum of 150 000 bpd
- Western Canadian Select (WCS) crude supply was limited to 50 000 bpd (33 vol% of crude blend)
- All products had a market demand
- Only three types of crude were evaluated in the crude final blend: WTI, Arab Medium (ARM) and WCS
- Sufficient hydrogen was available for purchase
- No additional VGO was purchased to fill the FCCU.

The US Environmental Protection Agency (EPA) has regulated through MSAT II that refineries must produce gasoline with an annual pool benzene content of 0.62 vol% or less in 2011 and beyond. The largest source of benzene in a refiner’s gasoline pool comes from reformate. Two methodologies exist to handle benzene reduction, including the pre-fractionation of naphtha to remove benzene and benzene precursors, and the post-fractionation of reformate to remove benzene. The refinery LP model was configured with a naphtha splitter and UOP Penex process unit to lower the benzene content. This unit also raises the octane number and RVP of the hydrotreated light naphtha to produce an on-specification gasoline blending product.

The LP optimised crude selection and flow rates to each unit based on the net variable margin (NVM). The NVM, expressed in $ per barrel of processed crude oil, is defined as gross margin minus utilities cost (NVM = gross margin - utilities cost). A total of eight cases were evaluated, as shown in Table 1. Additional details on the internal rate of return (IRR) and net present value (NPV) will also be discussed. 
Two general objectives were investigated that involved identifying the 
maximum amount of WCS that can be processed without investment and the processing options that maximise refinery profitability when processing WCS.

As the quality of the crude blend was degraded with increasing amounts of WCS, the model was configured to target as a minimum the same total gasoline plus diesel production as in the base case. The first case evaluated was a minimum investment option in which WCS was added to the crude blend until a major constraint was reached. As the content of WCS in the crude blend was increased, the LP model was allowed to reduce both WTI and Arab Medium (ARM) as needed. However, the LP model saw an advantage in backing down only on the WTI. Even though WTI crude has the largest crude naphtha yield, its higher cost relative to the other 
crudes evaluated was the controlling economic factor.

For the minimum investment case, only 3.0 vol% WCS could be added 
to the crude blend before constraints were reached in the coker, FCC and sulphur units. While this case did 
show an economic advantage over the base case, the NVM increased by only 0.5 $/bbl, which may not be sufficient to offset logistic problems associated with processing such a low quantity 
of WCS.

To detail the impacts associated with processing higher quantities of WCS, the LP model was used to evaluate both 15 and 33 vol% WCS in the crude blend with three processing options:
- Option 1 (FCC revamp): The FCCU was expanded along with all other units as needed to handle the higher quantities of VGO, carbon and metals.
- Option 2 (VGO hydrotreater): A new UOP VGO Unionfining process unit was added to improve FCC feed quality. The FCCU was constrained to a maximum throughput set by the base case, while all other units were allowed to expand as needed
- Option 3 (VGO hydrocracker): A new UOP VGO Unicracking process unit was added to improve the FCC feed quality and produce an improved product slate. The FCCU was constrained to a maximum throughput set by the base case, while all other units were allowed to expand as needed.

All three of the processing options resulted in a higher NVM compared to the base case (Figure 2). The NVM was also found to progressively increase with the quantity of WCS processed. To avoid redundancy, the following discussion is limited to the 33 wt% WCS case. Options 1 and 2 (FCC revamp and VGO hydrotreater cases) resulted in an increased NVM of about 5.0 $/bbl relative to the base case. Option 3 (VGO hydrocracking case) provided nearly 6.0 $/bbl of increased NVM relative to the base case.

Option 1: FCCU revamp
To enable a higher quantity of WCS to be processed, major expansions were required relative to the base case. As the WCS content was increased to 33% in the total crude blend, the following capacity expansions were observed:
- Sulphur unit (+110 wt% based on sulphur production)
- Boiler house (+96 wt%)
- Delayed coking unit (+48 vol%)
- Vacuum unit (+26 vol%)
- Unsaturated gas concentration unit (+23 vol%)
- FCCU (+15 vol%)
- HF alkylation unit (+14 vol%).

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