I can't recall an investment conference where I haven't received
at least one question about the potential of oil-rich plays such as
the Bakken Shale and Eagle Ford Shale. Interest in unconventional
oil fields has picked up in the wake of the Macondo disaster.
Whereas new regulations and permitting delays will hamper U.S.
deepwater drilling for at least another 12 to 24 months, onshore
shale plays offer the best prospects for production growth.
Prospective investors should note
the huge difference
between oil shale and oil produced from shale reservoirs, often
called shale oil.
Oil shale is an inorganic rock that contains a solid organic
compound known as kerogen. Oil shale is a misnomer because kerogen
isn't crude oil, and the rock holding the kerogen often isn't even
Liquid crude oil consists of organic material--plant and animal
remains--that's been exposed to heat and pressure over millions of
years. The slow transformation of organic material into oil
progresses through a number of stages. Kerogen occurs relatively
early in this process. To understand where kerogen fits into the
developmental timeline, consider that bitumen--the hydrocarbon
found in Canada's oil sands--represents a later stage in the
process. In a sense, bitumen is a higher-quality and more useful
hydrocarbon than kerogen.
To generate liquid oil synthetically from oil shale, the
kerogen-rich rock is heated to as high as 950 degrees Fahrenheit
(500 degrees Celsius) in the absence of oxygen, a process known as
There are several competing technologies for producing oil
) has developed a process for creating underground fractures in oil
shale, filling these cracks with a material that conducts
electricity, and then passing currents through the shale to
gradually convert the kerogen into producible oil.
Royal Dutch Shell
(NYSE: RDS.A) buries electric heaters underground to heat the oil
Although estimates of the cost to produce oil shale vary widely,
the process is more expensive and energy-intensive than extracting
crude from Canada's oil sands. Producers would require oil prices
of roughly $100 a barrel before this capital-intensive process
would be feasible on a commercial scale.
In the early 1980s Exxon embarked on a massive effort to produce
oil shale in Colorado. The so-called Colony Oil Shale project was
expected to cost $5 billion--an exorbitant amount in 1980--but the
investment appeared worthwhile based on prevailing oil prices and
the company's optimistic production forecasts.
But a collapse in oil prices forced Exxon to write off a $1
billion investment. It was one of the most dramatic boom-and-bust
cycles in energy industry's history. A few larger companies
continue to work on oil shale, and plenty of smaller outfits market
themselves to unsuspecting investors with tales of massive reserves
locked in oil shale.
This article doesn't focus on the oil shale fairy tale but
rather a number of shale oil reservoirs located around the U.S.
Shale oil plays such as the Bakken have far more in common with
unconventional gas plays such as Appalachia's Marcellus Shale and
Louisiana's Haynesville Shale than they do with Colorado's oil
What makes an oil or natural gas play unconventional?
Hydrocarbons don't occur in giant underground pools but are trapped
in the pores and cracks of a reservoir rock. Conventional reservoir
rocks such as sandstone feature high porosity and permeability.
That is, they have many pores capable of holding hydrocarbons as
well as fissures and interconnections trough which the oil or gas
can travel. When a producer drills a well in a conventional field,
oil and gas flow through the reservoir rock and into the well,
powered mainly by geologic pressure.
Shale fields and other unconventional plays aren't particularly
permeable. In other words, these deposits contain plenty of
hydrocarbons but lack channels through which the oil or gas can
travel. Even in shale fields where there's plenty of geologic
pressure, the hydrocarbons are essentially locked in place.
Producers have developed and refined two major technologies in
recent years to unlock the natural gas and oil trapped in shale
deposits--horizontal drilling and fracturing. The first technology
is self-explanatory: Horizontal wells are drilled down and sideways
to expose more of the well to productive reservoir layers.
Fracturing is a process whereby producers pump a liquid into a
shale reservoir under such tremendous pressure that it cracks the
reservoir rock. This creates channels through which hydrocarbons
can travel, improving permeability. Over the past several years,
U.S. producers have perfected these techniques in a number of
prolific shale gas plays. Now more and more of these exploration
and production (E&P) firms are applying the same techniques to
a handful of established and emerging shale oil plays.
Producers are increasingly finding that long horizontal
wells--"long laterals" in industry parlance--and huge multistage
fracturing jobs maximize output from shale deposits. For example,
in the Bakken producers routinely drill laterals that exceed 10,000
feet in length, a distance of nearly two miles. Plenty of producers
do fracturing jobs in more than 30 stages, and a few are
contemplating fracturing projects of 42 stages or more. As
technology and drilling techniques evolve, output and efficiency
continue to improve.
The results explain why exploration and production outfits
have rushed to secure acreage in the most promising
. Not only do these fields produce crude that's often of better
quality than West Texas Intermediate (the U.S. standard that's the
basis for NYMEX futures), but break-even costs are also far lower
than in the deepwater.
In the core of the Bakken, for example, producers need oil
prices in the $35 to $40 range to earn solid returns on their
drilling programs. At current oil prices, some producers enjoy
internal rates of return in excess of 100 percent.
As you can see, it's important not to confuse shale oil projects
with oil shale. With this distinction in mind, let's examine some
of the largest horizontal shale oil plays in the U.S. and their
prospects for future growth.
The Bakken Shale occupies the Williston Basin, a vast area
centered in North Dakota and Montana. The play
also extends into Canada
, though the U.S. portion is generally considered to be more
prospective for oil. The map below shows exactly where this play is
Energy Information Administration
Rocks are deposited in layers. The Bakken comprises three layers
of shale--an upper, middle and lower Bakken--located at a depth of
between 8,000 and 11,000 feet in the play's most productive areas.
Drilling activity targets the Bakken's middle layer, a naturally
fractured shale rock that contains a light, sweet high-quality
Some parts of the play include another productive formation, the
Three Forks-Sanish. Operators initially characterized the Three
Forks as an area where oil that spilled out of the Bakken
collected. But drilling results increasingly suggest that the
Bakken and Three Forks are actually separate plays; activities in
the Three Forks formation don't sap production from nearby Bakken
The Williston Basin and Bakken Shale aren't new discoveries--the
first wells were drilled back in the 1950s. Technology and
techniques were the real discovery.
The simple vertical wells sunk in the 1950s failed to produce
oil at high rates. A vertical well travels straight through the
Bakken formation, but the only productive part is the 50 to 100
feet of the shaft that touches the middle Bakken. In contrast, a
horizontal well drilled along the productive layer exposes
thousands of productive feet to the well. In addition, hydraulic
fracturing supplements the middle Bakken's natural fractures,
further enhancing productivity
In 2000 E&P firms drilled the first horizontal wells in the
field. Since then, several major producers have ramped up activity
to the point that the Bakken has emerged as the leading onshore oil
play in the continental U.S. The graph below tells the tale.
Click to enlarge:
Energy Information Administration
This graph tracks crude oil production in Montana and North
Dakota from 1981 onward. Output from the Bakken area is expected to
top 350,000 barrels per day in 2010. Given that these states
produce roughly 370,000 barrels per day, the data serves as a good
proxy of total production from the Bakken.
As you can see, oil output declined in both states from the
mid-1980s to 2002-03, when production surged. More recently,
production from Montana has declined slightly because operators
have shifted their focus to the North Dakota side of the play.
Estimates of the basin's potential production growth vary
widely. Conservative estimates put the figure at 500,000 to 750,000
barrels per day over the next five years. Aggressive estimates
suggest that the Bakken could yield 1 to 1.5 million barrels per
day in a half-decade. Based on recent well results and comments
from producers, I tend to believe that production will approach the
high end of these estimates--assuming oil prices remain strong.
As for recoverable reserves, in 2008 the U.S. Geological Survey
((USGS)) estimated that the field contained 3.65 billion barrels of
oil, 1.85 billion cubic feet of gas and 148 million barrels of
NGLs. Investors should note that this estimate fails to reflect the
increasingly productive Three Forks-Sanish play. Initially regarded
as a gross overestimate, the USGS figure is now regarded as quite
), the leading player in the field, pegs the region's recoverable
reserves at 24 billion barrels.
But don't get vertigo from these dizzying reserve estimates;
what really matters is production, how many barrels of oil per day
the play generates. Under the most optimistic assumptions, the
region could produce about 1.5 million barrels per day by 2015, a
drop in the bucket compared to U.S. oil consumption of 20 million
barrels per day.
Don't believe the hype about the Bakken enabling the U.S. to
become energy independent or an oil exporter. That being said, the
field is large enough that it will have a meaningful and lasting
impact on U.S. oil production growth.
As far as investors are concerned, low production costs ensure
that, at current oil prices, many producers are generating returns
in excess of 100 percent for each well drilled. Most wells pay for
themselves in 1.5 to 3 years. The economics become even more
attractive in the event of higher oil prices. Companies with
attractive acreage positions in the Williston Basin should be able
to grow profits significantly in coming years.
Eagle Ford Shale
Petrohawk Energy Corp
) in 2008, the Eagle Ford is located in south Texas and consists of
three distinct windows, depicted in the map below.
Click to enlarge:
Wells in the northern part of the play, or oil window, produce
mainly crude oil, though it also contains smaller volumes of
natural gas and NGLs. Located just to the south of the oil window,
the wet-gas region produces gas along with high volumes of NGLs.
The play's southernmost window contains mostly gas.
Depressed natural gas prices have ensured that much of the
drilling activity to date has occurred in the oil and wet-gas
windows, a bias that should persist for the foreseeable future.
In terms of economics, some of the field's sweet spots offer
returns rivaling those in the Bakken. With several producers
planning to step up drilling in the area, you can expect to hear
more about the Eagle Ford in coming years.
Exploration and production (E&P) firms are notoriously
tight-lipped about their acquisition programs and initial discovery
wells for fear of instigating a land rush and losing out on prime
properties. But whenever an explorer announces compelling drilling
results in uncharted or forgotten territory, the competition pays
attention--and opens up their wallets.
That's exactly what happened when
) revealed at its 2010 Analysts Conference that it had accumulated
400,000 net acres in the Denver-Juneburg ((DJ)) Basin, a
sedimentary field in Colorado's eastern plains as well as parts of
southern Wyoming and western Kansas and Nebraska. EOG's holdings in
the DJ basin are concentrated in northeast Colorado and part of
Wyoming. What management has identified as the core part of this
play is near existing infrastructure in the Hereford prospect.
Click to enlarge:
Confirmation of early results from #2-01H Jake set the industry
abuzz. Drilled in the third quarter of 2009, the horizontal Jake
well produced at a maximum rate of 1,558 barrels of oil per day
from a 3,800-foot lateral. After 90 days, the Jake had produced
50,000 barrels of oil.
Although additional test wells have failed to live up to the
Jake--perhaps because of restricted flows and different drilling
techniques--the announcement sparked a massive land grab in the
region. Early movers secured leases at $350 to $500 an acre. But
these days, real estate in the play's most prospective areas goes
for more than $3,000 an acre. Wyoming has reported bids as high as
$5,900 per acre in land auctions held this summer.
Amid all this excitement, it's important to note that early
results suggest that the Niobrara likely contains multiple core
areas as well as some regions that are duds. Moreover, as
) CEO often points out, the Niobrara effectively consists of two
plays: the well-documented Wattenberg Field where Noble Energy and
other operators have sunk a number of vertical wells and
less-developed areas that have set investors' imaginations
Well results from Noble Energy have demonstrated the benefits of
horizontal drilling in areas rife with vertical wells. Remember
that these vertical wells only come into contact with a small
fraction of the oil-rich shale. Noble Energy's tests indicate that
the average horizontal well in the Wattenberg yields 10 times the
IP rate of a vertical well, seven times the recovery and double the
As of this writing, much of the Niobrara has yet to be
de-risked. Third-quarter conference calls from EOG Resources and
Noble Energy should include additional well results and could
provide insight into each company's 2011 drilling program. Rest
assured that we'll be monitoring these developments closely.
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