The Bright Future of Shale Gas
While the successful Barnett Shale has become one
of the hottest plays in North America, it has
overshadowed the achievements of several other
shale gas plays. In this issue, I will examine shale
gas, the five US basins that currently produce it as
well as several emerging plays.
Shale gas is essentially natural gas contained
within a sequence of predominantly fine grained
rocks, dominated by shale. (Source: CSUG) Shale
gas plays are considered area plays since shale gas,
similar to coal bed methane (CBM), is often found
over large contiguous areas. Most shales have low
matrix permeabilities and require the presence of
extensive natural fracture systems to sustain
commercial gas production rates. (Source: GTI).
The low permeability of shale gas reservoirs
results in recovery rates of only 20% of original
gas in place compared to 75% for conventional
reservoirs.
In general, shale reservoirs have the following
characteristics:
?? low production rates (20 thousand cubic feet
per day (mcf/d) to 500 mcf/d) but cover very
large areas;
?? long production lives (up to 30 years);
?? low decline rates -- generally less than 5% per
year (typically 2% to 3%);
?? ability to be thick (up to 1,500 feet);
?? typically organically rich;
?? contain large gas reserves (5 billion cubic feet
(bcf) to 50 bcf per section);
?? rely on natural fracture systems for porosity
and permeability (matrix por/perm very low);
and the requirement for stimulation (fracing) to
be economic.
(Source:ibid)
Similar CBM, interest in shale gas increased
following the passage of Section 29 tax credits that
became available with the passage of the 1980
Crude Oil Windfall Profits Tax Act. Section 29
tax credits allowed producers of natural gas from
unconventional reservoirs, such as shale and CBM
reservoirs, to enjoy a tax credit of approximately
$1.05 per mcf for natural gas produced from
unconventional reservoirs. The gas had to be sold
before December 31, 2002 from wells drilled prior
to 1993.
The combination of tax credits and advances in
technology has helped shale gas production
increase steadily since the early 1980’s. Advanced
fracturing fluids and horizontal drilling are two of
the more important technological advances.
Today, shale gas accounts for approximately 3% of
total US natural gas production. (Source: GTI)
The shale play that got the US natural gas industry
started was drilled in the early 1820’s in Fredonia,
NY. The gas from this well was used to light local
streets. Modest production from Devonian shale
wells in the Appalachian Basin began around the
1920’s and has continued to present day.
2
Devonian shale gas is defined as natural gas
produced from the fractures, pore spaces, and
physical matrix of shales deposited during the
Devonian period of geologic time. Devonian
shales occur predominantly in the Appalachian,
Illinois, and Michigan basins. The shales formed
approximately 350 million years ago in a shallow
sea that covered the eastern half of what now
constitutes the continental United States. Organicrich
muds and silts were deposited in the sea and
were subsequently buried by younger sediments.
The high pressures and temperatures that
accompanied burial of the sediments resulted in the
formation of natural gas from the organic material.
Cumulative production from Devonian shales has
been less than 3 trillion cubic feet (tcf), mostly
from the Big Sandy Field in Kentucky and adjacent
fields in West Virginia. Current production is only
about 0.1 tcf per year. Because of its history,
Devonian shale gas maybe thought of as a
“conventional” gas resource. It is also an
unconventional gas resource because of its
complex geology, required use of advanced
exploration and extraction technologies and the
need for high gas prices to make production
economical. (Source: Gas From Devonian Shale,
Princeton University, 1985)
The success of the Devonian-age Antrim Shale
play in Michigan is probably the one of the better
documented and more mature Devonian-age shale
plays. The play stretches across the northern
Lower Peninsula from Lake Michigan to Lake
Huron and is found at depths typically between
1,000 and 1,800 feet. However some operators
have reported successful wells as shallow as 400
feet and as deep as 2,500 feet. The Antrim shale is
similar to CBM in many ways. Like most coals,
the pore space in the shale is initially water-filled.
This water must be removed from the formation to
allow for maximum gas production rates. Twelve
to 18 months of dewatering are required before
peak production rates are achieved. According the
most active operator in the Antrim Shale,
Quicksilver Resources (NYSE:KWK), the typical
Antrim shale well will produce 400 to 800 million
cubic feet (mmcf), have peak daily production of
between 125 and 200 mcf/d for one to two years
after de-watering, decline 8-10% per year, cost
$175,000 all-in and have a productive life of
approximately 20 years.
With over 7,800 wells drilled into the Antrim shale
since full scale development began in the late
1980’s, the play is nearly fully exploited.
However, for the early developers of the Antrim
shale, such as KWK and Petroleum Development
Corporation (a Model Portfolio company), the play
will provide continued outstanding returns for
years to come.
One of the more promising Devonian age shale
plays is being developed by Eastern Consolidated
Oil and Gas (a wholly-owned subsidiary of
Consolidated Energy). In November 2004, Eastern
Consolidated announced very positive results from
the company’s first Devonian shale gas well in
Morgan County, Kentucky. During a 72 hour
blow-down test, the well produced 472 mcf/d.
Eastern Consolidated plans to drill seven additional
offset locations to further their understanding of
the play.
Operators hoping to repeat the success of the
Antrim Shale in the Illinois Basin have so far been
disappointed. Activity in the New Albany Shale
peaked in 1996 with 90 wells, but has declined
substantially in recent years due to lack of success.
Operators are currently experimenting with various
drilling and completion techniques in an attempt to
improve well performance and reduce costs. Well
costs have ranged from $100,000 to $150,000,
depending on water lifting requirements and the
type, number and size of stimulation treatments
needed. While exploration of the Devonian shale
in the Illinois Basin has yet to yield commercial
success, operators are hoping that a combination of
high gas prices, technology and trial and error will
lead to commercial success.
The Lewis shale formation, found primarily in the
San Juan Basin of New Mexico and Colorado has
been producing gas on a commingled basis since
the early 1990’s. The key difference between the
Lewis Shale and those in other basins, according to
David G. Hill, manager, emerging resources, with
the Gas Technology Research, and Charles R.
Nelson, a principal project manager with GTI, is
that operators are not developing the Lewis as a
stand-alone play. The zone is completed as either
3
a secondary completion zone in new wellbores
targeting deeper conventional sandstone reservoirs,
or as a recompletion target in existing wells, where
gas from the Lewis is commingled with production
from deeper zones.
Gas production from Lewis Shale completions
averages about 100 to 200 mcf/d, and exhibits very
shallow, stabilized annual decline rates of about
6%. Lewis Shale completions produce very little
water or condensate and provide incremental
projected economic recoverable reserves of .05 to
2.0 bcf per well.
While this commingling strategy makes the Lewis
Shale extremely economic - an incremental cost of
only about 30 cents per mcf - it also makes it
difficult for operators to quantify the incremental
production rates, reserves and corresponding value
of the Lewis. Burlington Resources (NYSE:BR),
the largest producer in the prolific San Juan Basin,
is clearly finding value in the Lewis Shale. Since
the early 1990’s, the company has been recompleting
existing wells (over 600 wells to date)
to produce from the Lewis shale formation.
Far and away the most productive shale gas play in
the US is the Barnett Shale play in the Fort Worth
Basin. While the Barnett Shale has been one of the
more popular onshore plays over the last couple of
years, its success was a long time in the making.
The unlocking of the value of the Barnett Shale
began in the early 1980’s when Mitchell Energy
(now part of Devon Energy) began experimenting
with foam fractures in an effort to increase flow
rates. Today, operators are using a variety of
advanced fracturing techniques and horizontal
drilling technology to substantially increase
production rates. According to a presentation on
Quicksilver’s website, several operators in Johnson
County have drilled horizontal wells that are now
producing in the 2.1 to 5 mmcf/d range.
So just how big is the Barnett Shale? The play
continues to expand outward from its core Newark
East field and currently produces 1 bcf/d. While it
will be years before an accurate estimation of the
ultimate recovery from the play can be made, the
US Geological Survey recently estimated total
shale gas in place of 26.7 tcf. While this is an
impressive figure and one that is likely to increase,
the more important number will be how much gas
can be extracted.
The Barnett Shale, similar to all other shale plays,
is really a recovery factor play (i.e. improvements
in technology are the key to unlocking the
significant amounts of gas in place). With current
recovery rates in the Barnett Shale of only 8 to
15% and natural gas prices remaining at their
current historically high levels, there is a strong
likelihood that advances in horizontal drilling and
completion technologies will improve today’s
recovery rates.
The most exciting new shale gas play is the
Fayetteville Shale near Conway County, Arkansas.
After three years of quietly expanding its acreage
position, Model Portfolio member Southwestern
Energy (NYSE:SWN) made significant progress
on its 500,000 acre Fayetteville Shale project last
year. In its application for a development permit
from the Arkansas Oil and Gas Commission, SWN
provided a wealth of information on the play.
SWN indicated that modeling data for two of its
test wells suggest an expected drainage area of 30
acres or less per well, estimated gas-in-place of 58
to 65 bcf per square mile and an estimated ultimate
recovery of 580,000 to 600,000 mcf per well.
Assuming continued positive results and a
favorable price environment, the company plans to
drill up to approximately 160-170 wells in 2005 in
its Fayetteville Shale play.
With several companies in the early stages of
delineating other shale natural gas plays and
continued production growth from existing plays,
there is little doubt that shale gas production in the
US will continue to grow for years to come. Due
to the long life nature of shale gas plays, the
substantial advances in technology in recent years
and today’s high commodity price environment,
the economics of shale gas have never been better.
Savvy investors should seek out companies that are
leaders in the development of new shale gas plays
to take advantage of the significant wealth creation
potential these types of plays offer.