June 18, 2013 / 3:32 PM / 4 years ago

COLUMN-Shale hampers diesel maximisation: John Kemp

(John Kemp is a Reuters market analyst. The views expressed are his own)

By John Kemp

LONDON, June 18 (Reuters) - U.S. refiners’ efforts to boost output of diesel and other middle distillates, now the most profitable products from oil refining, are being complicated by soaring production of shale crudes.

In 2012 distillate fuel oil accounted for a record 29 percent of output from U.S. refineries, up from less than 22 percent in 1993.

Rising production of distillate fuel oil to meet increasing demand for road diesel has come mostly at the expense of residual fuel oil and gasoline, according to the Energy Information Administration (EIA).

But growing output from shale formations, which produce light crudes more suitable for making gasoline than diesel, threatens to throw the diesel maximisation process into reverse.


In the last two decades, U.S. refiners have improved their processes to maximise diesel production without major capital expenditure. Some have also invested in expensive hydrocrackers, able to break up heavy molecules destined for bunker fuel into lighter and more valuable molecules suitable for use in diesel or gasoline.

But the crudes they use are more important than a plant’s process configuration in determining diesel yields, according to a study prepared by the EIA on “Increasing distillation production at U.S. refineries” published in December 2010.

The EIA concluded that refiners could boost distillate yields (including jet fuel) up to a theoretical maximum of 49 percent by processing heavy crudes, optimising their processes and employing a hydrocracker. Light crudes such as those from shale would yield a maximum of only 37 percent under the same conditions.

These are ideal yields. Actual distillate yields would be lower. But the study illustrates the advantages of processing medium and heavy crudes to maximise diesel.


For more than 50 years, U.S. refiners almost always sold gasoline at a higher price than diesel and have focussed on maximising gasoline production. By 1993, refiners were producing twice as much gasoline as distillate fuel oil.

But over the past two decades, the demand for diesel outside the United States has been growing much more rapidly than for gasoline and other refined products.

Dieselisation has been especially pronounced in Europe, where favourable fuel taxes have pushed the proportion of diesel cars from 13.8 percent in 1990 to 32 percent in 2000 and 46 percent in 2009.

Dieselisation has unbalanced the world fuel market and left refineries struggling to produce enough distillate while they make too much gasoline.

The European Union is set to phase out the tax preferences for diesel after recognising the constraints on the refining system.

Meanwhile, U.S. refiners have responded by becoming major distillate exporters. Between 2004 and 2012, distillate exports have risen every year, climbing from 110,000 barrels per day to over 1 million.

U.S. distillate prices have moved to a premium over gasoline prices since 2005, and refiners have scrambled to wring every last drop of diesel from the crude they refine (Chart 1).


Chart 1: link.reuters.com/pub98t

Chart 2: link.reuters.com/rub98t



The simplest way to boost diesel production is to invest in a hydrocracking unit. Hydrocrackers take heavy molecules left over from vacuum distillation, catalytic cracking or coking and break them apart into smaller molecules by applying heat and tremendous pressure in the presence of a catalyst and hydrogen.

Hydrocrackers were originally installed to maximise gasoline production. But by turning down the temperature and selecting the right catalyst, refiners have been able to repurpose them to boost distillate.

As a bonus, the hydrogen reacts with any sulphur contained in the feedstock to form hydrogen sulphide, which can be removed, so the hydrocracker produces very clean fuel that meets specifications for ultra-low sulphur diesel (ULSD).

Hydrocrackers have become one of the most useful units in a modern refinery. U.S. refiners have doubled their hydrocracking capacity from 900,000 barrels per day in 1982 to 1.9 million in 2012, according to EIA.

In 1982, hydrocrackers could be employed to upgrade just five barrels out of every 100 fed into a U.S. refinery. By 2012, that had doubled to 10.5 barrels (Chart 2).

In its “World Oil Outlook 2012,” OPEC predicted the utilisation rate for hydrocrackers around the world would be over 90 percent through 2020 to meet the strong demand for diesel.

Installing a hydrocracker can boost a refinery’s distillate yield by 4 to 8 percentage points, according to Valero, the largest independent refiner in the United States.

Unfortunately, hydrocrackers are very expensive. Special steels are needed to contain the severe conditions needed for the reaction (up to 2,000 pounds per square inch at 750 degrees Fahrenheit) and resist intrusion by the hydrogen leading to brittleness and failure.

Hydrocrackers also give off large amounts of heat, so careful controls and elaborate quenching systems are needed to prevent runaway cracking.


In the short term, many refiners have focused on process improvements, which can boost diesel yields by 3 to 5 percentage points without the need for significant capital expenditure.

The simplest change is to expand the range of liquids sent for middle distillate production, rather than gasoline or heavy gasoil production, by changing the “cut points” in the distillation tower and downstream conversion units.

Normally, middle distillates include all streams with a true boiling point between 400 degrees and 650 degrees Fahrenheit. By expanding the range slightly to include liquids that boil between 360 and 700 degrees, some of the liquids previously sent to gasoline production and heavy gasoil can be retained as distillates instead.

The problems are potential loss of quality and the need to have enough hydrotreating capacity to remove sulphur from all the extra distillate being made so that it meets the specifications to be sold as road fuel.

Diesel production can also been improved by better fractionation.

In theory, middle distillates include all molecules boiling between about 400 and 650 degrees. In practice “the quality of distillation in commercial refinery units is sloppy”, according to the EIA. Large numbers of molecules that should be retained as distillates instead end up in the gasoline pool or as heavy gasoil.

More accurate separation can boost diesel yields while improving the quality of gasoline. European refiners have long had an incentive to squeeze every drop of diesel they can from the distillation and downstream units. U.S. refiners are still some way behind.

Nonetheless, in response to a spike in distillate prices in summer 2008, U.S. refiners have raised diesel yields mostly by process improvements and cut gasoline yields, according to the EIA.


In 2008, refiners squeezed more extra diesel from medium and heavy crudes than from light ones. Refineries processing light crudes with an average density of 35 degrees API raised their distillate yield by 3 percent, but refineries processing heavy crudes under 28 degrees API boosted their yield by 5 percent.

Shale oil from formations such as Bakken is even lighter than Brent and WTI, averaging more than 40 degrees API, so it is not a good fit for refiners aiming to maximise diesel output.

Bakken yields much more gasoline and far less distillate than other domestic crudes such as Louisiana Light Sweet (LLS) and Alaska North Slope, according to Continental Resources, one of the Bakken pioneers.

Process improvements can go only so far to offset the impact of changes in the crude slate.

U.S. refiners continue to blend shale oil with imported medium and heavy crudes from Saudi Arabia and other countries to improve diesel yields. But it may not be enough to produce as much diesel as they would like to sell. (editing by Jane Baird)

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