of the mixture is usually sand and water. Many states
are now requiring companies to disclose the chemi
cals used in the fracking process.
Finding oil and gas used to be as much an art as a
science, but advances in computer-processing power
now allow geologists to interpret seismic surveys
with greater accuracy and to produce three-dimen
sional images and underground maps of hydrocarbon-
bearing formations that rriay exist in thin layers of
rock (less than 50 feet thick), 5,000 to 10,000 feet or
more below the surface. Think of the subsurface as
a multiple-tiered layer cake, with the hydrocarbon-
bearing layer (the pay dirt) being the thin layer of
chocolate fudge frosting holding the two bottom cake
layers together. New directional drilling technolo
gies, including horizontal drilling, allow companies
to turn comers and follow thin hydrocarbon-bearing
formations for thousands of feet in a mostly horizon
tal direction to reach more oil and gas from one spot.
Hydrofracking can then be done at multiple locations
along a horizontal borehole to stimulate the recovery
of greater quantities of oil and gas from one well.
With today's technology dry holes are becoming far
less prevalent. Technological advances have reduced
drilling costs and financial risk and have allowed for
greater recovery efficiencies that make it possible for
companies to go after previously uneconomic, unre
coverable reserves like deep shale oil and gas.
Hydrofracking requires huge amounts of water (up
to five million gallons per well) that is scarce in many
locations, and concerns have been raised about pos
sible contamination of drinking water. At most sites,
however, fracking occurs far below the water table at
depths of 3,000 feet or more that are separated from
the aquifer by solid geological barriers. Neverthe
less, there are instances currently under investigation
where some older, shallow wells have been subjected
to hydrofracking in and below the aquifer in close
proximity to drinking water.
Another issue involves the recovery, treatment and
disposal of the wastewater and chemicals used in the
fracking process. Some states used to allow wastewa
ter from fracking operations to be sent to municipal
wastewater treatment plants for treatment and dis
charge, but that practice has largely been stopped.
In many states, wastewater must now be captured,
treated and reused wherever possible, which makes
sense where water is scarce. In the eastern states,
wastewater is disposed of in deep injection wells
drilled just for the purpose of disposing the frack
ing liquids. There have also been some instances of
well blowouts where fracking fluids have spilled out
on the surface to pollute farmland, lakes, ponds and
streams.
Industry standards and state and federal regula
tions governing hydrofracking are evolving rapidly
to deal with these issues. The Environmental Protec
tion Agency (EPA) is conducting a broad study of
the fracking process with a view toward developing
standards for the process itself and for the capture,
treatment and disposal of wastewater, but preliminary
results are not due until 2013. In May of 2011, EPA
Administrator Lisa Jackson, testifying before the
House Oversight and Government Reform Commit
tee, said, I'm not aware of any proven case where the
fracking process itself has affected water.although
there are investigations ongoing. She also testified
that Natural gas creates less air pollution than other
fossil fijels so increasing America's natural gas pro
duction is a good thing.
The U.S. shale oil story is good news for many
reasons. We are the world's largest consumer and im
porter of oil and the world's third-largest oiF producer
behind Saudi Arabia and Russia. U.S. production of
crude oil peaked at about 9.6 million barrels per day
(mmbd) in 1970, and then declined steadily to a low
of 5.0 mmbd in 2008. Total U.S. liquid fuel produc
tion, which includes not only crude oil but also other
liquid fuels like condensates, natural gas liquids and
biofuels, was 7.5 mmbd in 2008. Since 2008, howev
er, total U.S. liquid fiiel production has risen by about
1.2 mmbd, with the increase in crude oil accounting
for the largest share. Half of the rise in U.S. crude oil
production was from the deep-water Gulf of Mexico,
and half was from new shale oil developments in
North Dakota, Texas and other places.
Minor shale oil production began in North Dakota
almost 50 years ago, but shale's potential could only
be realized when high oil prices and the cost-effec
tive application of horizontal drilling and hydraulic
fracturing allowed production to rise from 10,000 bpd
in 2003 to 500,000 bpd today. Today, North Dakota is
about to pass California to become the nation's third
largest oil-producing state behind Texas and Alaska.
The rise in shale oil production will take over from
the deep water Gulf of Mexico as the largest incre
mental source of crude oil production grovi^h in the
next 10 years, adding a total of about 2.0 mmbd to
U.S. production between now and 2020. This growth,
coupled with smaller gains in deep water production,
biofuels, and natural gas liquids will help to offset
continued production declines in older fields and help
us limh our dependence on oil imports
Our dependence on oil imports reached a peak of
over 60% in 2005, but it has since declined to just
49% in 2010, partly as a result of increased domestic
production. In 2010, almost half of our net oil imports
came from the Western Hemisphere (Canada, Mexi
co, Venezuela and others), and less than one-fifth of
our imports came from the Persian Gulf While the
U.S. Department of Energy's (DOE) Energy Informa
tion Administration (ElA) expects U.S. oil demand
to resume growing slowly over the long term, the
expected increases in our domestic production of all
liquid ftiels together, including shale oil, may further
limit our dependence on oil imports to just over 40%
of our expected consumption in 2035. While shale oil
and increased imports from Canada and other friendly
suppliers will help to limit our dependence on poten
tially unreliable sources of oil, we will still be part of
the global oil market and economically vulnerable to
supply disruptions and price hikes.
The natural gas story is even more dramatic. The
U.S. is the world's largest producer and consumer of
natural gas, but our production of gas was fairly stag
nant for years up to about 2006. In the early 2000s,
our imports of natural gas, primarily coming by
pipeline from Canada, reached a level of nearly 20 %
of our consumption, and there was a great expectation
that U.S. gas imports would continue to grow. Cana
dian gas production was also stagnating, and Canada
began to use more of its own gas in the production
of syncrude. As a result, just a few years ago the
U.S. was perceived as a growing market for liquefied
natural gas (LNG) imports from many international
suppliers. In 2004, the Federal Energy Regulatory
Commission (FERC) was entertaining more than 40
requests for siting permits to build LNG receiving
terminals along the U.S. coastline. Gas producers in
many parts of the world invested billions of dollars in
gas liquefaction plants, export terminals and ships to
supply the U.S. market, only to see U.S. demand for
imports dry up in the space of a few years because of
increased U.S. production.
High natural gas wellhead prices stimulated the
industry to experiment with a combination of hori
zontal drilling and hydraulic fracking in the Barnett
shale in Texas. Early success with the technique in the
Barnett led the industry to focus on other shale plays
in Haynesville (La.), Fayetteville (Ark.), Marcellus/
Utica (Penn., Oh., NY, W.Va.), and others. The rest
is history. Shale gas production went from 0.3 tril
lion cubic feet (TcO in 2000, to almost 5.0 Tcf today,
and it now accounts for almost 25 % of our total gas
production. Our imports have dropped to about 10
%, and wellhead and spot natural gas prices have
declined by more than half, to a level around $3.00
per thousand cubic feet (Mcf) today from more than
$8.00 per Mcf in 2008.
The DOE/EIA now expects shale gas production to
continue rising to more than 12 Tcf by 2035, when it
will account for nearly 50 % of our total gas produc
tion. The EIA also expects natural gas prices to stay
below the highs experienced earlier, which could
allow it to gain market share, primarily at the expense
of coal in electricity generation (but also nuclear and
renewables like solar and wind), and possibly in the
transport sector, at the expense of oil, as a fijel for
trucks and buses. On an energy equivalent basis, the
wellhead price of natural gas today is roughly only
about 20 % of the cost of oil. Abundant supplies of
inexpensive natural gas couldn't have arrived at a bet
ter time. The EPA's new utility regulations on emis
sions of mercury, acid gases and soot, coupled with
their proposed regulations on emissions of carbon
dioxide could lead to the closure of about 20 % (or
about 60,000 megawatts) of our coal-fired electric
ity generating plants between now and 2016. This
capacity is likely to be replaced by new, clean-bum-
ing, efficient, combined-cycle natural gas plants that
produce the lowest-cost power available today.
(Continued on page 6)
February 2012 I The Shoreline