The decline in crude prices and global refined product shift away from fuel oil to highly regulated middle distillates has compelled a number of refiners to shift future investments towards deep processing units, such as hydrocrackers, delayed cokers and vacuum units. Analysts believe that falling global demand for refined products, with fuel oil in particular, has compelled refiners to produce higher-value middle distillates. In spite of postponement of previously announced projects, cheap feedstocks combined with low plant energy and utility costs (steam, hydrogen, etc.) are mitigating fixed operating costs. When projects do go forward, they will be configured to reflect a shift to a distillate-dominated market, at the expense of traditional gasoline and fuel oil production.
Commitment to new deep conversion units were announced on a regular basis in 2014. For example, last July ExxonMobil said it planned to invest over $1 billion at its 320,000 bpd refinery in Antwerp, Belgium, enabling the plant to convert heavy, higher sulfur oils into marine gasoil and diesel. Then in September, the company’s affiliate in Norway, Esso Norge AS, announced plans to enable production of high quality VGO with investment in a crude vacuum unit at its 120,000 bpd (6 million metric tonne) Slagen refinery, reducing heavy fuel oil while boosting middle distillates production. The project, designed to convert heavy fuel oil into desulfurized diesel and ultra low sulfur heating oil, also consists of a solvent de-asphalting unit and a mild hydrocracker, scheduled for start-up in early 2016.
The September 3 announcement on the ExxonMobil website also noted that “ExxonMobil and its affiliate is investing for the future at its Slagen refinery despite low margins and industry-wide losses in Europe.” While low priced shale crudes and LTOs have been available to refiners in the U.S., European refiners are also gaining access to relatively low cost Middle Eastern crudes. While these Middle Eastern crudes are heavy and high-sulfur, it is nonetheless projected that Saudi Arabia will ramp up production of high-quality light sweet crude by 2016 from its newest super giant oilfield, the Shaybah formation in the country’s remote Empty Quarter. Over 1.0 million bpd of Arabian Extra Light crude is expected to be produced from this field by the end of 2016 (see “Aramco Makes Final Investment Decision on Shaybah Oilfield,” January 21, 2014, The Economist). This could possibly give some European refiners access to crude of comparable quality to high-quality shale crudes available to many U.S. refiners.
Also last summer, Total and Russian Lukoil’s 155,000 bpd Zeeland refinery in Flushing, the Netherlands, completed a hydrocracker upgrade. With numerous hydrocracker project announced since 2014, there is little doubt that refiners plan to shift away from fuel oil as stricter environmental regulations come into force affecting sulfur content in bunker fuels. However, according to KBC’s Mel Larson, “One must be careful in romanticizing the value of the hydrocracker. Hydrocracking diesel selectivity is 50-55%. Thus, on a nominal volume increase of 120%, most of the products from a diesel-selective hydrocracker will be Jet and lighter.” Larson also emphasized that, “Though hydrocracker diesel selectivity is greatest when cracking gas oil (650-1000°F), the whole product slate must find a value-added home. Producing more catalytic reformer feed [from hydrocracked naphtha] into a depressed gasoline market competes with the need to produce alkylate for Tier 3 gasoline. Hydrocracked naphtha is not typically suitable for olefins and/or aromatics production, so nominally 30% of the hydrocracker yield must be sold into an over-supplied market.”
ULSD standards in North America and Euro-5 standards in Europe are also influencing export oriented refinery configurations. For example, the Kazakhstan government recently announced that by January 1, 2016, all of their refineries will meet Euro-5 gasoline and diesel production standards, which were implemented to help curb motor vehicle pollution. However, the motivation is different for U.S. refiners, should export opportunities come to fruition for shale feedstock-rich U.S. refiners. On this development, KBC’s Larson said, “Export fuel qualities are not required to meet U.S. fuel standards. If the export market is open to the refiner, diesel has been and will continue to be of greater value than gasoline.” Related to this development, Larson also said, “Refinery operations and asset mixes that allow for improved selectivity to diesel will continue to have an incentive in the incremental market. The new wrinkle is the impact of light tight oil (LTO), which are sweeter (less sulfur), cost less and have a higher native concentration of naphtha-to-diesel boiling range components than West Texas Intermediate (WTI), for example. Therefore, market demand for transport fuels can be met with LTO processing at low severity (less cracking). Further, LTO yields high-quality diesel (>50 Cetane), which is suitable for export to the high-value European market.”