(Repeats June 2 item; no changes to text)
By John Kemp
LONDON, June 2 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
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
"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
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
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
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
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
Distilled products are taken from the tower in six or seven
broad "cuts" or streams, which correspond to groups of nearby
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,"
"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.
OPTIONS RUNNING OUT
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
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
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."
(Editing by Dale Hudson)