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HomeTop NewsU.S. refiners struggle with too much light crude: Kemp

U.S. refiners struggle with too much light crude: Kemp

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A Chevron refinery

Most of the extra oil produced in the United States in the next two years will be light crudes and condensates that domestic refineries will struggle to process – intensifying pressure for at least a partial relaxation of the country’s export ban.
U.S. oil production is set to increase by another 2 million barrels per day in 2014-15. More than 60 percent of the forecast growth will consist of light oils with a specific gravity of 40 degrees API or higher, according to the U.S. Energy Information Administration (“U.S. crude oil production forecast: analysis of crude types”, May 29).
But with imports of competing crudes from West Africa already reduced close to zero, U.S. refineries will be unable to process all this extra oil without enormous investment in equipment.
Distillation towers, furnaces, heat exchangers and downstream conversion units would need expensive and time-consuming overhauls to enable them to handle a higher share of light oil.
“Projects designed to alter the refinery configuration or expand refining capacity take much more time (than building rail links and pipelines). Permitting is generally longer because there is a greater environmental impact and the engineering construction is longer,” Valero, the largest refiner in the United States, warned investors in a conference call in March.
“Many refinery projects take two years to permit and can take at least two years to build. If you decide to do something today, it takes four or five years before your investment is operational,” the company explained (“Refining technical teach-in call transcript”, March 4).
Processing a higher share of light oil would also leave refineries unable to make full use of the expensive coking units installed in the 1990s and 2000s, when they expected to be handling more medium and heavy grades.
Refiners will make another round of changes only if they expect light grades to stay at a significant discount over the long term, which remains unclear. Without investment, refiners will demand even bigger discounts for handling unsuitable domestic crudes. If prices drop low enough, production could be curtailed.
Crude is a blend of thousands of different hydrocarbons, ranging from small, light molecules with low boiling points to large, heavy ones that boil at very high temperatures.
Refineries separate raw crude into a series of fractions with similar boiling points by distillation. They then employ various conversion and upgrading processes to alter the proportion in each boiling range and improve the characteristics prior to sale as gasoline, kerosene, heating oil, heavy fuel oil, lubricating oil or bitumen.
Cracking and coking break apart large molecules into smaller ones, reducing the proportion of low-value products such as residual fuel oil and increasing the amount of premium fuels such as diesel.
Alkylation combines smaller molecules into larger ones, turning very light molecules into premium fuels such as high-octane gasoline.
Reforming and isomerisation alter the structure of molecules to increase their octane rating.
Hydrotreating and hydroprocessing react distillation products with extra hydrogen (manufactured from natural gas) to remove impurities such as sulphur and nitrogen and break larger molecules into smaller, more valuable ones.
By employing a combination of distillation, conversion and upgrading processes, a refinery can turn raw crude into as many as 30 products meeting strict specifications.
Refineries use complex linear programming models with 3,000-7,000 separate equations to tell them which crudes to buy and blend.
In general, though, refineries need to operate all their units as close to capacity as possible to maximise returns and pay for the expensive equipment. The result is that refineries are quite restricted in the blend of crudes they can run.
“Each refiner has been designed and built to process a specific range of feedstocks and although some refiners are more flexible in terms of what you can feed into that refinery, there has been capital invested in that site in order to gain that flexibility,” Valero explained.
“Profitability is maximised by maximising (the throughput) rate. Generally, maximising rate means that we’re going to run a feedstock diet which is very close to what the refinery was designed to run,” the company said.
“There are other times, however, that the markets dictate that we run a feedstock that’s significantly different … (which) generally means lower refinery run rates and lower refinery utilisation.”
The crude distillation unit (CDU) is the first and largest unit in any refinery. Every barrel of raw oil is run through the CDU to separate it into basic fractions before these are sent for further processing.
The distillation column contains a stack of 50 or more bubble trays. Crude is heated and vaporised near the base of the tower and the constituents condense on different trays, depending on their boiling point. Lighter molecules condense on trays at the top of the tower while heavier molecules condense lower down.
Distilled products are taken from the tower in six or seven broad “cuts” or streams, which correspond to groups of nearby trays.
Distilling a lighter feedstock rather than a heavier one will result in more liquids coming off the top of the tower and fewer in the streams lower down.
Processing more light oils can therefore lead to congestion at the top of the tower as the “distillation tower is unable to handle increased vapour traffic from light components”, according to Valero (“Basics of refining and processing additional light sweet oil”, Feb. 25).
Lighter oils also require extra heat input, so the furnace must be larger.
“The yield of light gases – methane, ethane, butane, propane – at the top of the tower is about three times higher from a light crude barrel than you would see from a heavy barrel so we quickly run out of capacity in this section of the refinery,” Valero explained.
“Many times when we try to run lighter crude, we run out of furnace capacity. Replacing a crude furnace is fairly capital-intensive and requires a difficult permit to obtain.”
The greater volume of gases and liquids coming off the top of the tower also creates problems in the downstream units.
Most refineries do not have enough reforming, isomerisation and alkylation capacity to handle all the extra light streams.
At the same time, there is less volume coming from streams at the bottom of the distillation column, leaving cracking and coking units underutilised.
Some problems can be fixed simply and cheaply. For example, the configuration of trays and cut points in the distillation tower can be adjusted without too much difficulty and expense.
But replacing a distillation tower or furnace, or installing more reformers and alky units, costs hundreds of millions of dollars.
Refiners have tried to exploit lower-cost options first. The simplest is to substitute light domestic crude for imported crudes with similar characteristics.
For the most part, U.S. refiners have substituted growing light sweet output from the Bakken and Eagle Ford shales for similar crude oils imported from Nigeria and other parts of West Africa.
But the process of backing out light foreign crudes has almost run its course. U.S. refiners imported just 5.6 million barrels of Nigerian crude in the first three months of 2014, down from 83 million barrels in the same period of 2011.
So far, refiners have been able to hold the average API of their crude blends almost constant by switching foreign for domestic oil. But with U.S. production forecast to rise by another 2 million barrels per day in 2014-15, refiners are running out of room to manoeuvre.
One option is to start reducing the amount of medium and heavy oil they process, but that would almost certainly mean cutting runs to deal with the problem of extra light streams. Refiners would need big discounts for light oils to compensate for the loss of throughput. The other option is to permit at least some light oils to be exported.
In 2013, Maria van der Hoeven, head of the International Energy Agency, writing in the Financial Times, cautioned:
“Some may see this as a choice between keeping American oil within U.S. borders for reasons of economic security and allowing the U.S. to generate billions of dollars in new export revenues. Market realities suggest a far simpler decision ahead: either U.S. crude is shipped abroad or it stays in the ground.”

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