Oil From U.S. Fracking Is More Volatile Than Expected
High Gas Content Extends Beyond North Dakota's Bakken Shale to Colorado and Texas
June 24, 2014 7:42 p.m. ET
Millions of barrels of crude oil
flowing from shale formations around the country—not just North
Dakota—are full of volatile gases that make it tricky to transport and
to process into fuel.
Oil from North Dakota's Bakken Shale field has already been identified as combustible by investigators looking into explosions that followed train derailments in the past year.
But
high gas levels also are affecting oil pumped from the Niobrara Shale
in Colorado and the Eagle Ford Shale and Permian Basin in Texas, energy
executives and experts say.
Even the
refineries reaping big profits from the new oil, which is known as
ultralight, are starting to complain about how hard it is to handle with
existing equipment. Some of what is being pumped isn't even crude, but
condensate: gas trapped underground that becomes a liquid on the
surface.
The federal government says 96% of
the growth in production since 2011 is of light and ultralight oil and
that is where growth will continue.
The
huge volume of this gassy new oil has created a glut, pushing prices to
$10 or more below the level of traditional crude. Energy companies think
they could get higher prices by sending the new oil abroad, which
explains some of the push to lift a U.S. ban on exporting crude. Federal
officials recently gave two companies permission to export condensate under certain circumstances.
This
new crude can act like a popped bottle of Champagne, says
Sandy Fielden,
an analyst with consulting firm RBN Energy. "If it's very light,
it froths over the top" of refinery units, he says. Many refiners "can't
manage that in their existing equipment."
Valero Energy Corp.
VLO -0.69%
says two refineries in Texas and Oklahoma received batches of
unexpectedly gassy oil and had to slow fuel production to deal with it.
The company is investing more than half a billion dollars to add special
equipment at several plants so it can process more light oil.
Many refiners already are investing
in upgrades to process more of this new oil, but the volume could still
overwhelm them. Others will have to make the costly shift, says
Matt Rogers,
a director at consulting firm McKinsey & Co.
Until
a few years ago, the oil available to U.S. refiners was dirty and
heavy. Refiners spent billions of dollars on equipment to turn that gunk
from Venezuela and Canada into gasoline and diesel.
That
has changed as oil companies began using some of the same techniques,
including hydraulic fracturing, that produced the natural-gas boom. U.S.
oil production rose by 3 million new barrels a day between 2009 and
2013, bringing the country's total output to 8.4 million barrels a
day—the highest level since 1988.
There
are geologic reasons that the new oil is particularly gassy and
volatile. Over millions of years, organic material turns into a brew of
hydrocarbons: crude oil, natural gas and other gas-infused liquids. The
longer that fossil-fuel mixture cooks underground—in intense heat and
under tremendous pressure—the more molecules escape from their source
rocks and migrate to reservoirs where there is room to move around, says
Scott Tinker,
the state geologist for Texas.
In
those reservoirs, the oil and gas separate into less-dense gas on top
and heavier crude oil below, much like a shaken vinaigrette settles into
distinct layers.
But shale rock is so
dense that much less oil and gas escapes from it. The energy industry
must frack shale to create tiny fissures so that oil and gas can flow
out. Those minuscule pathways let only the smallest molecules rise,
which is why large volumes of gas and the lightest liquids are coming
out of the ground.
In most cases,
ultralight oil doesn't look like black gold. In fact, it can be as clear
as water and some oil from the Eagle Ford Shale in Texas brims with so
much dissolved gas that it bubbles, giving the appearance of boiling at room temperature.
That
gas makes ultralight shale oil highly combustible in a way conventional
crude is not. In the past year, derailments of trains carrying light
crude have resulted in spectacular blowups, including an explosion that
killed 47 people in Quebec last July.
Refining executives complain that some ultralight liquid is getting mixed in with higher-price traditional crudes.
Greg Garland,
the chief executive of
Phillips 66,
PSX -0.83%
told analysts recently that there was no question that "people
are blending condensate" into West Texas Intermediate, the U.S.
benchmark, to try to pass it off as regular crude and get more money for
it.
That's not to say that light crude
isn't worthwhile—as long refiners are prepared for it. Gulf Coast
refiners used to import light crude but today they have replaced most of
it with oil from U.S. shale. Some experts warn that without new
equipment, refineries will soon run out of capacity for ultralight oil
pumped in the U.S.
Consultants at Bentek
Energy forecast that without a change to U.S. export policy that allows
oil to be exported, an oversupply of ultralight oil will drag the price
of West Texas Intermediate to $80 a barrel by 2019 from $106 today—a
level that would cause some companies to stop drilling.
Lifting
the U.S. export ban, which has been in place since the 1970s, requires
congressional action. Companies can export refined fuel. The Commerce
Department, in what is known as a private ruling, recently said
Pioneer Natural Resources Co.
PXD -0.78%
and
Enterprise Products Partners
EPD +0.74%
LP could export condensate after it has been minimally processed.
Tom O'Malley,
chairman of refiner
PBF Energy Inc.,
PBF -3.39%
says the industry can engineer its way around the growing glut of
volatile, ultralight oil without export changes. His company revamped a
Delaware refinery built to process heavy crude into that one that
receives more than 100,000 barrels a day of Bakken oil by train.
Gulf Coast refiners could follow suit, he says. "If we could do it, they can do it."
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