Jun-2017

Tier 3 gasoline from tight oil crudes

Assessing process schemes to counter loss of gasoline road octane when the crude feed includes tight oil

TEK SUTIKNO and KEVIN TURINI
Fluor Enterprises Inc

Article Summary

Gasoline sold in the US will be required to meet 10 ppmw average sulphur content starting 2017. To comply with this Tier 3 ultra low sulphur gasoline (ULSG) regulation, North American refineries supplying gasoline in the US will need to assess timely modification options required to achieve the new gasoline desulphurisation target. While the US will implement this Tier 3 standard starting 2017, some industrial regions of the world have mandated this regulation for several years, and some developing nations will likely follow the 10 ppmw sulphur average limit in the future. Meanwhile, hydrofracturing technology has increased US domestic production of tight oil with API 41-57 or higher to about 4.7 million b/d. This production, which is roughly more than a quarter of US crude consumption, is estimated to continue to 2035 and beyond.¹ While the ban on crude oil exports from the US has been lifted, US refineries would likely need to consider this available domestic crude when developing a refining scheme modification plan to comply with the increasingly more stringent gasoline sulphur limit.

To remain competitive with the volatile crude prices and price differentials among different quality crudes, recently completed refinery revamp projects in the US generally have the goal of processing a higher percentage of heavy crudes in the crude slates, and these heavy crudes include diluted bitumen (dilbit) in which the vacuum residue fraction amounts to about 35 vol%. These projects for refining heavier (API 21), high sulphur crudes typically involve expansion of heavy fraction processing units such as the vacuum unit and coking unit, along with increased throughput and improved performance in the areas of thermal cracking or hydrocracking for converting the heavy fraction to lighter products.

Tight oil, on the other hand, has around 5 vol% or less of vacuum residue fraction, compared to about 35% in heavy crudes such as dilbit (see Figure 1). Both WCS and Cold Lake are dilbit crudes typically containing 27-30 vol% of naphtha diluent. Dalia is an example of a conventional heavy crude (with API 23.7) from Africa. Relative to conventional light crudes such as WTI or Brent, tight oil contains higher naphtha and lighter fractions and a much higher middle distillate fraction. As such, refining excessively higher percentages of tight oil in the crude slates will require expansion of the naphtha and distillate complexes and result in heavy fraction processing units such as the vacuum unit operating under design capacity.

For refineries which have been revamped to process heavy crudes, processing crude slates with an excessively high percentage of tight oil could lead to under-utilisation of new assets recently modified or added for processing heavy crudes. Dependent upon the differential prices for crude types, crude blends of bitumen and tight oil might be financially lucrative to refine in the future, but crude incompatibility challenges² and other issues such as limitations of equipment in light fraction services will need to be analysed to avoid operating problems and off-specification products.

In addition to presenting common revamp options for meeting Tier 3 gasoline specification, this article discusses some of the issues associated with refining crudes containing tight oil. To add the flexibility for refining the maximum, viable percentage of tight oil in the crude feed, these issues may need to be addressed in timely fashion when defining the overall refinery revamp modification scope for Tier 3 compliance.

Tier 3 compliance
While the most cost-effective processing scheme for Tier 3 compliance will vary depending on the existing refining configuration, most of the gasoline-oriented refineries in North America typically have a fluid catalytic cracking (FCC) unit contributing to about 30-50% of the gasoline pool and the majority of sulphur compounds in the gasoline. These refineries expectedly comply with the prevailing Tier 2 requirement or would otherwise need to sell the off-specification gasoline to other refineries. For refineries with a FCC unit, processing Tier 3 gasoline will typically involve desulphurising catalytic naphtha from the FCC, light straight run (LSR) naphtha, butanes, and naphtha produced from downstream processing units such as coking. Heavy straight run (HSR) naphtha and heavy naphtha from downstream conversion units will typically be hydrotreated to produce feed for a catalytic reforming unit. For refineries meeting Tier 2 gasoline requirements, reformate and other gasoline blending components such as isomerate, alkylate, and hydrocracker naphtha typically do not require further treatment.

Desulphurising FCC naphtha to comply with the Tier 3 target generally involves FCC feed pretreatment and/or FCC naphtha post-treating (see Figure 2). A FCC feed hydtrotreater, or catalytic feed hydrotreater (CFH), is the common type of feed pretreatment which reduces sulphur content as well as nitrogen and metals contents in the FCC products. This CFH option has the primary benefits of increasing the yields of LPG, FCC gasoline, and light cycle oil (LCO, a diesel feedstock) and significantly reducing FCC flue gas SOx emissions.³

Compared to the other viable desulphurisation options, however, the CFH option has the highest capital expenditure requirement, consumes more hydrogen, and increases sulphur production in the sulphur recovery system. For US refineries already meeting Tier 2 gasoline standards without a CFH, installing a new CFH will be financially more favourable from the higher yields of FCC products especially if future price differentials for high and low sulphur crudes can justify the capital investment. Roughly, the sulphur content ratio of FCC naphtha to FCC feed is about 1:20. Even refining the available shale tight oil or other sweet crudes with sulphur contents as low as 0.1 wt%, the untreated FCC feed sulphur content could exceed 1000 ppm3, and the FCC naphtha in this case will not likely meet the Tier 3 requirement of 10 ppmw. To meet this target, FCC feed pretreatment or FCC naphtha post-treatment, or both, are generally necessary.

Most US refineries are equipped with a CFH, but only a small percentage (around 15%) of these refineries can reportedly meet the Tier 2 target with a CFH only.⁴ The majority (about 70%) of these refineries have both CFH and FCC naphtha post-treatment to comply with the Tier 2 target, and further modifications are necessary to meet the Tier 3 sulphur target.

For refineries with an existing CFH only, the sulphur content of the hydrotreated feed will need to be reduced to 200 ppmw to yield FCC naphtha with 10 ppm sulphur, if the sulphur content ratio of FCC naphtha to FCC feed follows the 1:20 estimate. As FCC naphtha typically amounts to 30-50% of the gasoline pool, the maximum allowable sulphur content of FCC naphtha will be in the range 20-30 ppmw to stay at 10 ppmw maximum sulphur content in the gasoline pool when the sulphur contents of the remaining gasoline pool components are negligible.⁵ Even with the targeted 30 ppmw sulphur in the FCC naphtha, the CFH generally needs to reduce the FCC feed sulphur to around 400-600 ppmw by increasing the severity of desulphurisation. This reduces catalyst cycle life, increases hydrogen demand, and affects synchronisation of the turnaround schedules for upstream or downstream units, in addition to changes in product yield distribution from the FCC unit. All of the impacts from more severe operation of a CFH will need to be evaluated along with other options such as:
• Undercutting the FCC naphtha product boiling end point for reducing sulphur content
• Using new catalyst types for extending cycle length
• Revamping the CFH to a mild hydrocracker
• Revamping the FCC to yield more LCO or LPG.

The post-treatment option for FCC naphtha or thermally cracked naphtha is achieved by either hydrotreating or otherwise treating part or all of the naphtha. Relative to the FCC feed pretreatment, post-treating FCC naphtha requires lower capital costs for ultra low sulphur gasoline. Post-treating processes alone are typically sufficient for meeting the Tier 3 requirements. Post-treating has been the approach of choice for most US refineries. While conventional naphtha hydrotreating can desulphurise the FCC naphtha, saturation of olefinic compounds leads to significant reductions of the research octane number (RON or R) and motor octane number (MON or M). Dependent upon the olefinic content of the hydrotreater feed and the required extent of desulphurisation, octane number reductions can exceed 10 with high consumption of hydrogen and shorter catalyst life cycle. As FCC naphtha amounts to 30-50% of the gasoline pool, minimising the loss of octane number in post-treatment hydrotreating of FCC naphtha is essential. As indicated later, octane loss could become more severe when a refinery increases the percentage of tight oil in the crude feed.