SBA Consulting projects that global base oil demand will be flat for the next five years, around 36 million t/y. As a result, some 13 million t/y of nameplate capacity, predominantly API Group I, must be shuttered. By 2017, Group I should constitute only one third of the global base oil pool, down from 58 percent in 2010, said Ames.

Two million t/y of new paraffinic base oil capacity streamed in 2011 and another 2.2 million t/y is scheduled for 2012. Beginning in 2013 through 2016, said Ames, 35 additional projects will add an additional 9 million t/y.

And not all the new capacity is paraffinic, Ames continued. Three projects through 2015 will add 855,000 t/y of new naphthenic capacity, and three polyalphaolefin projects next year will add 63,000 t/y of Group IV. A number of large, efficient Group I plants may be upgraded to Group II over the next five years, and capacity creep – debottlenecking – should provide 1.9 million t/y of additional capacity over the next five years. Its capacity leap, not creep.

The reason for this seemingly irrational excess, said Ames, is that todays base oil drivers are mainly external to the lubricants business. Ames listed two primary and three secondary factors driving base oil supply.

Emissions legislation is the first primary, long-term driver. Stringent fuel sulfur legislation and growing demand for distillate fuels requires new hydrocracking investment of $1 billion or more per plant. And global distillate fuel demand is projected to grow at three times the rate of gasoline demand. Three million barrels per day of new hydrocracking capacity will be needed by 2015 and a further 6.3 million b/d by 2030, said Ames.

Most new diesel hydrocrackers produce a potential feedstock for new Group II/III base oil operations. Around 17 to 23 million tons per year are possible from the three million b/d of new hydrocrackers. Not all will build base oil plants, but many are possible.

The second primary driver, said Ames, is the technology paradox: the highest quality base oil has the lowest cost of production. As a result, Group II/III capacity will continue to be built, and higher cost, small scale operations will close. Of these, most are Group I and many are in Europe.

Secondary base oil drivers include refinery upgrading and optimization (which allows use of heavier crude slates and greater diesel yields, often at the expense of Group I production); refinery viability (particularly in the Atlantic basin, fuel demand is down, refining margins are depressed, and base oil plants depend on the health of their mothership); and refinery divestment (most major oil companies are divesting refineries, and buyers may or may not choose to operate base oil plants included with the deals).

In 2010, SBA Consulting estimated that Group I accounted for 58 percent of total global base oil supply. Group II accounted for 24 percent; Group III for 7 percent; naphthenics for 10 percent; and PAO/PIOs for 1 percent. By 2017, said Ames, Group Is share will shrink to 33 percent; Group II will make up 40 percent; Group III, including gas-to-liquids, 15 percent; naphthenics, 11 percent; and PAO/PIOs, 1 percent.

To bring base oil supply and demand back into balance, closures would need to keep pace with new capacity. But the shake-out is likely to extend well beyond the five-year forecast period, Ames concluded.