Challenges and opportunities of 10 ppm sulphur gasoline: part 2

Economic evaluation of processing options for ultra-low sulphur gasoline compares severe pretreatment with a combination of pre- and post-treat solutions


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Article Summary

An emerging worldwide standard for ultra-low-sulphur gasoline (ULSG) as well as the challenges of increased heavy crude supplies and the 
gasoline/diesel imbalance demand careful consideration and selection of processing options. Part 1 of this article (see PTQ, Q3 2012) discussed commercially proven configurations that are available to meet these constraints and maintain profitability. An economic study, presented here, was also conducted to determine the best scenario to meet ULSG requirements: severe FCC feed pretreatment alone or less severe pretreatment coupled with FCC gasoline post-treatment. The impact of catalytic feed hydrotreater (CFHT) cycle length requirements, with and without post-treatment, was also examined.

An existing refinery reconfigured to process heavy Canadian crudes while maintaining its FCC unit was assumed. The VGO feedstock consists of a 55 000 b/d blend of straight-run VGO and heavy coker gas oil with 4.2 wt% sulphur. Due to the refractory nature of this feed, it has to be hydrotreated in a high-pressure unit prior to feeding the FCC unit, and the resulting gasoline constitutes about one-third of the total gasoline pool and all of the pool sulphur. The following three cases were considered:
• Case 1: A high HDS CFHT unit and FCC unit capable of producing 10 wppm gasoline pool sulphur without the need for a FCC post-treatment unit with a CFHT cycle length of four years to match the FCC unit
• Case 2: A moderate HDS CFHT designed for a four-year cycle length with a FCC post-treatment unit (Prime-G+), also designed for a four-year cycle length to meet ULSG pool specifications
• Case 3: Similar to Case 2 but with a two-year cycle length target for the CFHT unit combined with a Prime-G+ unit designed for a four-year cycle length. During the CFHT catalyst change-out, the Prime-G+ unit will operate at a higher severity to meet pool sulphur requirements.

For all cases, a relatively high pressure was selected for the CFHT to ensure good hydrogen addition during the whole run. Reactor residence time was adjusted to meet the CFHT HDS and cycle length requirement (see Figure 1). The very severe level of HDS and four-year cycle length in Case 1 naturally lead to a much larger CFHT than the other cases. High-purity hydrogen is supplied from a steam methane reforming plant.

A block flow diagram illustrating the three different cases with the various configurations along with the corresponding products considered for the economics is shown in Figure 2.

The economic evaluation was based on a discounted cash flow (DCF) analysis assuming a depreciation period and a project duration of 10 years. In addition, a profitability index comparison in terms of net present value (NPV) and internal rate of return (IRR) was conducted. The prices for investment, catalysts, utilities, feedstock and finished products were based on 2011 averaged values, assuming the plant to be located in the US serving a domestic market. Prices are presented in Table 1.

For all three cases considered, projections on CFHT and FCC operations were conducted, leading to expected product yields and hydrogen requirements. As one could have expected, the implementation of a high-severity CHFT (Case 1) leads to better product yields in the FCC unit, but has a major drawback of driving up hydrogen consumption. Results in terms of main product yields and hydrogen cost for each case are presented in Table 2. The evaluation was based on a natural gas price of $4 MMBTU, resulting in a hydrogen cost of $3.300 MSCF.

The hydrogen cost for Case 1 is almost 25% higher than for Case 2 or Case 3; however, the yield improvement is quite significant over the lower severity CFHT cases. Between the lower severity CFHT cases, the yields and hydrogen consumption are rather similar, with the more severe and longer cycle Case 2 providing a slight improvement in terms of yields over Case 3 commensurate with the small increase in hydrogen consumption.

With regards to the operating cost (opex) of the different cases, the study took into consideration the hydrogen, octane and utility costs. Compared to the other factors, the hydrogen cost was by far the major contributor to the opex. In addition to the operating cost, a detailed total capital investment (TCI) was developed to estimate the capex for each case.

The TCI trend illustrated in Figure 3 clearly shows that Case 1 has a much higher capital requirement than the other two cases due to the significantly higher desulphurisation and cycle length requirements for the CFHT.

Both net present value (NPV) and internal rate of return (IRR) comparisons are shown in Figures 4 and 5. High-severity CFHT without post-treatment, Case 1, was considered as the basis, and the IRR and NPV of the other cases were compared to Case 1.

The NPV results favour Case 1 with a high HDS/long cycle length CFHT and no post-treatment over more moderate HDS CFHT cases coupled with a post-treatment unit. On the other hand, the IRR is most favourable for Case 3 with the lowest cost CFHT option (moderate and two-year cycle) coupled with a four-year cycle post-treatment Prime-G+ unit.

A sensitivity case was examined to determine the impact of natural gas cost on the NPV results. The findings are highlighted in Table 3, where pricing is contrasted to the 2011 basis above. Assuming a higher natural gas price ($6 MMBTU vs $4 MMBTU), the cost of hydrogen increases and the difference in NPV between the three cases diminishes somewhat.

From an IRR perspective, the advantage of Case 3 increases when hydrogen cost increases and the gap in NPV between Case 1 and 3 decreases.

Surprisingly, Case 2 with a four-year CFHT cycle in sync with the FCC cycle does not show an NPV or IRR advantage over the shorter cycle Case 3 for either natural gas pricing scenario. One could have assumed that designing a CFHT in sync with the downstream units, compared to limiting the CFHT cycle length to only two years, would be an advantage. However, the four-year cycle post-treatment unit brings the additional flexibility to continuously operate during a CFHT catalyst change-out.


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