|
Study analyzes
US, shale gas plays
A
recent study has estimated that US shale-gas plays may produce as much as
24 bcfd by 2018.
|
Chesapeake
$412MM Sale of Anadarko, Arkoma Assets
Chesapeake Energy Corp. 1/5/2009
URL: http://www.rigzone.com/news/article.asp?a_id=71256
Chesapeake it has sold certain Chesapeake-operated long-lived producing
assets in the Anadarko and Arkoma Basins in its fourth volumetric production
payment transaction (VPP). Through the VPP, Chesapeake conveyed a royalty
interest to investors associated with Argonaut Private Equity. The purchase
was financed by GS Loan Partners, an affiliate of The Goldman Sachs Group,
Inc.
The assets include proved reserves of approximately 98 bcfe and current
net production of approximately 60 mmcfe per day for proceeds of $412 million,
or $4.20 per mcfe. Chesapeake retained drilling rights on the properties below
currently producing intervals.
The company previously announced its intention to complete a VPP by year-end
2008 as part of its plan to build larger cash reserves over the next two years.
The transaction, which closed on December 31, 2008, will be treated as a
sale for accounting purposes and the company’s proved reserves will be reduced
accordingly. |
Bossier Play Gastar Boasts Berlin-1 Top 10 Best Wells
Gastar Exploration Ltd. 1/5/2009
URL: http://www.rigzone.com/news/article.asp?a_id=71276
Gastar has successfully completed its best producing well to date, the
Belin-1, which was completed in two lower Bossier zones. The well is flowing
at a combined initial gross sales rate of 41.2 MMcf/day on a 20/64ths inch
choke with approximately 10,300 psi of flowing casing pressure. Gastar owns
a 52% working interest before payout (40% net revenue interest before payout)
in the Belin-1.
"The Belin-1 is our best producer to date, and based on the high quality
of the reservoir rock and the strong initial production rate, we expect it
will also be our best well to date in the Hilltop area in terms of estimated
recoverable reserves," said J. Russell Porter, Gastar's President and CEO.
"To put this well into perspective, our biggest producer prior to the Belin-1
was the Wildman-3, which IP'ed at 23 MMcf/day. Comparing it against the entire
play, we believe the Belin-1 is among the top ten best wells reported by any
producer in any area of the Bossier," he added.
"The Belin-1 contains the highest porosity rock we have drilled to date,
and we believe there is high-quality reservoir rock uphole from our initial
lower completions that could allow us to maintain strong flow rates well into
the future."
In addition, Gastar is currently drilling a sidetrack to the LOR-7 and
expects to reach total depth in approximately 5 to 10 days. Gastar has a
50% working interest before payout (37.5% net revenue interest before payout)
in the LOR-7. |
Trans Energy Completes
Fourth Vertical Well in Marcellus Shale
Trans Energy, Inc. 1/5/2009
Trans Energy's its Blackshere-101 well in Marion County, West Virginia
was successfully fraced on December 29th and is currently awaiting connection
to a sales line. The Blackshere-101 is completed in the Marcellus shale, a
prolific new "resource play" in Appalachia, similar to the Barnett, Fayetteville
and Haynesville shales which have grown to become a significant base of hydrocarbon
reserves in the United States.
James K. Abcouwer, President and CEO of Trans Energy, said, "This fourth
Marcellus well is located in Marion County which is the county to the east
of our existing Marcellus wells and is a step out of what we consider our
proven area. We are delighted with its initial indications. We are optimistic
that the positive results from our three vertical wells in Wetzel County and
now with our most recent completion in Marion County can be replicated throughout
our acreage position in northern West Virginia. We're now beginning a horizontal
well program in yet another significant step forward for Trans Energy to
properly develop its acreage position. We're pleased to have achieved this
sizeable acreage position centered on the Wetzel-Marion-Doddridge Counties
area, which looks to be one of the most -- if not the most -- prolific part
of the Marcellus resource in Appalachia." |
Marcellus - Cabot to hike Pennsylvania program
OGJ.com 12/27/08
Cabot Oil & Gas Corp., Houston, plans to boost production from Devonian
Marcellus shale in northeastern Pennsylvania in the next few weeks from the
current 1 3 MMcfd as it hooks up six vertical and three horizontal wells.
Meanwhile, the company expects to expand to eight rigs in 2009 from the
five currently working.
Cabot’s first horizontal Marcellus well came on line at 6.4 MMcfd after
a six-stage frac in its 2,000-ft lateral. Measured total depth is 8,925 ft.
Marcellus drilling totals 18 wells, 4 of them horizontal. The 2009 program
calls for 16 vertical and 7 horizontal wells. Four vertical and 3 horizontal
wells remain to be drilled in 2008.
Typical costs are $1.3 -1.5 million for a vertical well and $2.6-2.9 million
for a horizontal well. Average footage is 7,200 vertically and 2,200 ft laterally.
The company laid 10 miles of pipeline, started up one compressor with a
second unit standing by as produced volumes warrant.
|
Haynesville gas flows as high
as 28 MMcfd
OGJ.com 12/27/08
Three operators reported new horizontal completions in Jurassic Haynesville
shale at rates as high as 28 2 MMcfd of gas.
The three companies, Petrohawk Energy Corp. of Houston and Comstock Resources
Inc. and EXCO Resources Inc. of the Dallas area, plan much more activity in
the Haynesville in East Texas and Northwest Louisiana.
Petrohawk reported the 28.2 MMcfd rate at its Sample 9- 1 in 9-14n-l 1w,
Red River Parish, La., about 12 miles south of Elm Grove gas field. The rate
came on a 30/64-in, choke with 7,100 psi flowing casing pressure.
Petrohawk’s Brown 17-4 in 17-1 6n- 11w, Bossier Parish, gauged 23.4 MMcfd
on a 26/64-in, choke with 7,700 psi FCP And its Goodwin 9-5 in 9-16n-llw Bossier
Parish, made 21.1 MMcfd on a 26/64-in, choke with 6,750 psi FCP The company
plans to complete five more Haynesville shale wells by yearend 2009.
Initial flow rate is 9 MMcfd at Comstock’s BSMC LA 7-1 H well in Toledo
Bend North field, De Soto Parish. The flow came from a 4,300-ft lateral at
11,750 ft true vertical depth after a 10-stage frac.
Comstock is running another 10-stage frac at its Collins LA 15-IH well
in Logansport field, also in De Soto. It has a 4,200-ft leg at 11,350 ft.
The company has a 22% interest in the Gamble 24-1 H well at Logansport, drilled
to 11,800 ft TVD with a 3,950-ft lateral.
Comstock has drilled the vertical portion of two other Haynesville wells.
Bogue A-6H in Waskom field in Harrison County is to get a 4,000-ft lateral,
and Green 1 3H in Blocker field in Harrison County is to get a 3,700-ft lateral.
Comstock is drilling vertically at Headrick 1 H and Hart I H in Logansport
and Moneyham 7H in Longwood field. Each is due a 4,000-ft leg.
EXCO said its first Haynesville horizontal well, Oden 3 0H6 in De Soto
Parish, averaged 22.5 MMcfd on a 26/64-in, choke with 7,800 psi FCP It has
a 4,481-ft lateral at 12,304 ft TVD.
EXCO has two operated horizontal wells, one vertical well, and two outside-operated
horizontal wells in the play and plans to drill 25 or more horizontal Haynesville
wells in 2009. |
US gas production
Unconventional to soon
dominate
Source: http://www.platts.com 17-11-08
Higher gas prices and significant technological advances have led to a
dramatic increase in production of unconventional gas resources in recent
years, and that trend is expected to continue unabated, according to a study
to be released in the US.
By 2020, 69 % of US gas production and 43 % of Canadian gas will come from
unconventional plays, said the report prepared by energy consultant ICF International.
To support the production forecast, roughly 300,000 unconventional wells
will have to be drilled, representing an outlay of $ 560 bn for unconventional
gas drilling and related capital costs.
Previewing the report to the INGAA Foundation, or Interstate Natural Gas
Association of America Foundation, at its annual meeting in Palm Coast, Florida,
ICF analyst Harry Vidas pronounced it "good news for customers and policy
makers," asserting that the findings "show how well the natural gas industry
in the US and Canada has done in recent years stemming the decline" of conventional
gas production.
The outlook is "very optimistic," he continued. And with the tremendous
gains in production from tight gas, coalbed methane and, most significantly,
shale gas, this energy supply "is poised to be a very important part of North
America's energy future."
IFC noted that research and investment into unconventional gas has increased
significantly in recent years due to the higher price environment. In many
cases, the technologies for economic production had already been developed,
while in other cases resources were still in the research stages.
Unconventional gas had been a significant component of US production for
many years, but "its contribution has grown rapidly in recent years," the
report said, pointing to notable growth in production from tight gas reservoirs
in the Rockies and East Texas, coalbed methane in Wyoming and New Mexico,
and shale gas in North Texas and the Mid-Continent.
While tight gas figures to remain the dominant category of unconventional
gas through the study period of 2007-2020, the "most significant" trend, said
ICF, is the "rapid rise" of gas production from shale formations.
"It appears certain that shale gas production will expand in coming decades,
and production will emerge in new regions in the US and Canada."
ICF is forecasting growth in overall North American gas production from
last year's 25 tcf to 29 tcf by 2020. That gain will be "driven by onshore
unconventional gas," which is expected to grow from 42 % of total production
in 2007 to 64 % in 2020 and 72 % in 2030, Vidas told the INGAA Foundation
audience.
Total gas resources in North America exceed 2,300 tcf, said the report,
adding that shale gas accounts for roughly 500 tcf of recoverable resources
within that total. For the Lower-48 states, IFC put tight gas at 174 tcf,
coalbed methane at 65 tcf and shale gas at 385 tcf. The consultant sees production
from gas shales in the US growing from 1.4 tcf last year to 4.8 tcf in 2020,
and tight gas production jumping from 5.8 tcf to 9.2 tcf over the same span.
ICF said its forecast "may prove to be conservative, especially for gas
shales." It noted that the size of the recoverable resource base "is large
enough to support higher levels of annual production over the long term if
such production is demanded by the market." What's more, "it is likely that
our forecast of Western Canada is conservative, given the limited available
information on shale plays in British Columbia."
Also, several emerging shale plays, such as those in the Southeast US and
Rockies, are not included in the report due to scarce data.
The financial crisis and the recent decline in oil and gas prices may stunt
drilling programs, and some producers already have announced significant cutbacks.
"However, the longer-term need for energy in the US and Canada should be
strong enough to support the future levels of gas production presented here,
albeit on a possibly slower pace," said ICF.
The report also cautioned that environmental and regulatory issues may
dampen unconventional gas production efforts.
"These include well and environmental permitting and related costs, land
access, water use and disposal and surface disturbance."
Water use and disposal for fracturing of shale wells has already emerged
as a significant issue, ICF observed, "although, to date, water use has not
significantly restricted development in most shale areas." |
Pioneer Eagle Ford shale
gas production averaging 85 MMcfd
OGJ.com 12/27/08
Pioneer Natural Resources Inc., Dallas, is drilling the horizontal leg
in Cretaceous Eagle Ford shale in an exploratory well in DeWitt County, Tex.
This is about 90 miles east-northeast of where Petrohawk Energy Corp., Houston,
gauged an Eagle Ford gas-condensate discovery in LaSalle County (OGJ Online,
Oct. 21, 2008).
Petrohawk is completing its second well in LaSalle and is drilling in McMullen
County, Pioneer said.
Pioneer has logs through Eagle Ford from the more than 150 wells it has
drilled in the Cretaceous Edwards Trend along its 310,000-acre spread from
LaSalle to Lavaca counties and chose to horizontally drill the Eagle Ford
where it saw the best porosity Permeability is the question, the company
said Dec. 2.
Eagle Ford shale is the source rock for the Cretaceous Austin chalk and
Edwards formations, Pioneer noted.
Meanwhile, the company’s Edwards gas production is averaging 85 MMcfd.
|
Northeast US Millennium pipeline First Delivery 182-Mi.
Millennium Pipeline 12/22/2008
Millennium Pipeline Company, L.L.C. announced that its recently constructed
182-mile natural gas pipeline was placed into complete service today and deliveries
of natural gas supplies to its anchor shippers have commenced.
"This is an historic day for New York State and the Northeast," said Millennium
President Dick Leehr. "Many years of hard work and planning, permitting and
eventual construction have finally come to fruition, enabling Millennium to
deliver much-needed natural gas supplies as we enter the peak of the 2008-09
winter heating season. But the real winners are the energy users of today
and tomorrow, who now have a reliable new natural gas pipeline system that
will meet their growing need for clean-burning natural gas for years to come."
"It is gratifying to see that a major collaborative effort involving skilled
union workers from local communities and around the country, government officials
at all levels, customers, partners, contractors, vendors and many other organizations
came together to achieve this common important goal of meeting the region's
growing energy needs," Leehr added.
Millennium Pipeline began construction activities in 2007; however, the
majority of the 30-inch-diameter mainline pipeline installation work across
New York's Southern Tier and lower Hudson Valley was completed this year.
Some land restoration and environmental monitoring work will extend into
2009 and beyond. More than 2,000 workers -- many hired from local communities
-- were involved in construction of the pipeline.
More than 90 percent of the Millennium pipeline was installed within or
adjacent to existing pipeline rights-of-way. Millennium is the centerpiece
of a $1 billion investment in new energy infrastructure that includes new
facilities by Empire Pipeline, Algonquin Gas Transmission and the Iroquois
Gas Transmission systems.
Millennium Pipeline is anchored by its customers National Grid, Consolidated
Edison of New York, Central Hudson Gas and Electric Corporation and Columbia
Gas Transmission Corporation. Millennium will serve markets along its route
in the Southern Tier and lower Hudson Valley as well as providing essential
service to the New York City markets through its pipeline interconnections.
Millennium's design will allow it to transport up to 525,400 dekatherms per
day, based on market needs. Millennium is jointly owned by affiliates of NiSource
Inc., National Grid and DTE Energy. |
Williams Completes 1st Phase Pennsylvania New Jersey pipeline
Williams 12/22/2008
Williams has placed the first phase of its Sentinel expansion project on
its Transco natural gas pipeline system into service, increasing firm transportation
capacity into the northeastern U.S. by 40,000 dekatherms per day.
The Sentinel expansion project is being constructed in two phases. Phase
2 of the expansion will provide an additional 102,000 dekatherms per day and
is expected to be placed into service by November 2009. The entire Sentinel
expansion project is designed to increase Transco's firm transportation capacity
by 142,000 dekatherms per day.
"This is a major milestone and we sincerely appreciate our customers' commitment
to this project," said Phil Wright, president of Williams' natural gas pipeline
business. "We look forward to placing the remaining portion of this much needed
project into service and working with our customers to provide reliable natural
gas service for the northeastern United States for years to come."
Phase 1 construction has included the addition of approximately four miles
of 42-inch pipe in Northampton and Monroe counties, Pa., in addition to compressor
station upgrades at Transco Station 195 in Delta, Pa. Phase 2 will include
the addition or replacement of 14 miles of pipeline at various locations in
Pennsylvania and New Jersey. |
Colorado East -- Nighthawk
Energy Shale O/G production
Jolly Ranch Operational Update
The directors of Nighthawk Energy plc (“Nighthawk” or “the Company”) (AIM:
HAWK), the US focused hydrocarbon production and development company, are
pleased to announce an operational update in respect of the Jolly Ranch Group
project, located in Elbert, Lincoln and Washington Counties, Colorado. Nighthawk
holds a 50% interest in the project and the operator, Running Foxes Petroleum
Inc. (“Running Foxes”), holds the remaining interest.
Highlights
Jolly 10-5 well encounters hydrocarbons in multiple formations and is cased
for production. Ten commercial wells drilled at Jolly Ranch – 100% success
rate
Craig 15-32 well on three week production test from the Tebo shale bed
of the Cherokee formation presently producing 110 to 120 barrels of oil per
day
Four well drilling programme to test the prolific Codell and J Sand formations
commencing
The Jolly Ranch Group project is a major hydrocarbon production and development
venture which includes Jolly Ranch, currently the core area, Middle Mist and
Mustang Creek, to the north and west of Jolly Ranch respectively. The current
project area comprises 370,578 gross acres (281,069 acres on a net basis).
Drilling results to date have established Jolly Ranch as a significant
new oil and natural gas field, particularly in the Atoka and Cherokee shales.
These shales are laterally extensive and are believed to be continuous over
the entire project area. In addition, several oil bearing conventional zones
have been penetrated during drilling, including the Marmaton, Morrow, Spergen,
St Louis and Codell formations.
Jolly 10-5 well
The Jolly 10-5 well, the tenth of the drilling programme, has reached Target
Depth and encountered several hydrocarbon-bearing formations, both conventional
and unconventional. The well has been cased for production and will be put
on production in January 2009.
Craig 15-32 well
The Craig 15-32 well commenced production at the start of December from
a four foot Tebo shale, a component of the Cherokee shales, the first test
applied to this formation on the project. The oil is 38 API gravity, low paraffin
sweet crude and has a -10 degree pour point and no sulphur. The well commenced
production at 50 to 60 bbls of oil per day and has increased to 110 to 120
bbls of oil per day with less than 10% water.
As a result of this positive result from the Cherokee formation, two previously
drilled wells, the Craig 8-1 and Craig 4-4, have been completed in the Tebo
shale, are making oil and are presently being swab tested. The wells will
then be completed in the V and Excello shales also within the Cherokee formation
during the last two weeks of December and then placed on full production in
January 2009.
The Cherokee formation comprises four shales varying from three to six
feet thick for a net thickness of 15 to 22 feet. These shales contain 40%
to 80% quartz and carbonates, which, based on detailed analysis, are heavily
fractured and saturated with hydrocarbons. The Tebo B, Tebo, V and Excello
shales all have the same reservoir features. In addition, Omnilabs, a division
of Weatherford International, has indicated in detailed reports, that both
the Atoka and Cherokee shales in the project area are generating and expelling
hydrocarbons and showing characteristics typical of a successful shale play.
Codell and J Sand drilling programme
Black Gold Inc., a local drilling company, is commencing a four well drilling
programme to test the shallower Codell and J Sand formations, both prolific
producing zones in the region. Three wells, the Jolly 9C-1, Jolly 16C-1 and
Jolly 7-1 will test the Codell formation and the Fischer 14-20 will test the
J Sand formation in the Middle Mist Project.
These formations are of Cretaceous age and are located at depths of between
3,000 and 4,000 feet. The J Sand is a prolific producer in the central part
of the Denver Basin.
David Racher B.Sc (Hons) Geology, who is a consultant to Nighthawk and
has over 37 years of experience in the hydrocarbons industry and previously
managed the Lasmo plc onshore US portfolio in Kansas, Louisiana, South Dakota,
Texas and Wyoming, has approved the technical information contained in this
announcement. |
CNX Gas Marcellus Record rate -- 6.5 MMcf
CNX Gas Corp. 12/15/2008
CNX Gas Corporation reported that its first horizontal Marcellus Shale
well is now producing at a rate of 6.5 million cubic feet (MMcf) per day.
This is a record daily production rate for any well in the company's history
and is believed to be among the highest reported by any Marcellus Shale producer.
The well, located in Greene County, Pa., began flowing into the sales meter
on October 2, with an initial production rate of 1.2 MMcf per day and 4,000
pounds of backpressure, as previously reported. The backpressure on the well
had been gradually reduced since then, allowing daily production to increase
to about 4 MMcf per day until Friday, when the installation of new surface
equipment enabled the well to flow at the 6.5 MMcf per day rate, with pressure
still being held at 2,640 pounds. Cumulative production from the well prior
to last Friday was 106 MMcf.
Nicholas J. DeIuliis, president and chief executive officer, said, "This
was a team effort from our engineers, operators, and support personnel, including
the directional drillers from Scientific Drilling and the hydraulic fracturing
team from BJ Services. I can't speak highly enough of our Marcellus Shale
team.
"To achieve this kind of success with our first horizontal Marcellus Shale
well," DeIuliis continued, "speaks volumes about the breadth of our horizontal
drilling expertise. Many investors may not be aware, but CNX Gas had drilled
160 horizontal coalbed methane wells before drilling its first horizontal
Marcellus Shale well."
The well was drilled to a vertical depth of 8,140 feet in the Huntersville
Chert, penetrating 83 vertical feet of Marcellus Shale. The well was logged
then plugged back and a horizontal section of 3,395 feet was cut for a total
measured depth of 10,738 feet. The well was completed with a five-stage slickwater
fracture treatment using 3 million pounds of proppant.
CNX Gas has a 100% working interest in the well and a 100% net revenue
interest because CNX Gas does not pay a royalty. Because of the gathering
infrastructure already in place from its CBM operations, CNX Gas was able
to place the well online immediately after retrieving frac fluids. Also,
gas from production in southwestern Pennsylvania, as in other areas of Appalachia,
typically receives a premium over NYMEX pricing.
CNX Gas is currently drilling its second vertical Marcellus Shale well
and will be shortly hydraulically fracturing its second and third horizontal
wells. Updates on these wells will be provided during the company's next earnings
conference call, now scheduled for January 28, 2009.
CNX Gas is also raising its 2008 production guidance to 75 billion cubic
feet (Bcf) from 74 Bcf. The current guidance represents the third time guidance
has been raised from the original guidance of 72 Bcf. If the 75 Bcf is attained,
it would represent a nearly 29% increase from the 58.2 Bcf produced in 2007.
The company attributes the increased guidance to exploration success in both
the Marcellus and Chattanooga shales, as well as continued higher-than-expected
coalbed methane production. |
Baxter shale Wyoming Cretaceous
2.19 MMcfd
Oil & Gas Journal / Dec. 8, 2008
Devon Energy Corp. started production at the 5-3 Horseshoe Basin Unit well
in the Vermillion Creek area of the Greater Green River basin in Sweetwater
County, Wyo. Output from Cretaceous Baxter shale totaled 21.7 MMcf gas
and 3,836 bbl of condensate in the first 6.5 days on line, and the current
rate is 2.19 MMcfd and 412 b/d of condensate, said 50% working interest owner
Kodiak Oil & Gas Corp., Denver. TD is 13,534 ft. Three wells have
been drilled, and Devon is acquiring 25 sq miles of 3D seismic in the area.
The outlook for 2009 is for horizontal drilling in the Baxter, said Kodiak. |
Jurassic Haynesville/Bossier
shale Texas East
December 8, OGJ.com
GMX Resources Inc., Oklahoma City, said its Callison-9H well
in Harrison County, Tex., stabilized at 7.7 MMcfd of gas on a 22/64-in.
choke with 5,200 psi flowing casing pressure from Jurassic Haynesville/Bossier
shale. The company ran an eight-stage frac in the well’s 2,200-ft
lateral, its shortest planned lateral in the play. GMX has 100% working interest.
GMX is drilling the Bosh-1l H and Baldwin-I7 H wells and expects to spud
a fourth well within 2 weeks. The next 16 wells are expected to average 3,800-ft
laterals and 11-12 frac stages. The company plans to drill 45 wells in 2009.
The Belin-1 well in the Hilltop area of the deep Bossier play has the potential
to be Gastar Exploration Ltd.’s best well to date in terms of flow rate and
reserves, the company said. Logs indicated 150 net ft of pay in the middle
and lower Bossier formations. TD is 18,800 ft.
The well’s three Lower Bossier pay zones have the highest measured porosity,
up to 25%, of any well drilled by Gastar in the play.
Belin- also encountered two middle Bossier sands, including the Lanier
sand, in a downdip location in a new fault block with indicated pay based
on log analysis. The well, to be on line within 30 days, is to be completed
in the two deepest zones first.
The Lanier sand has been shown to be productive in a downthrown fault block
from the Wildman Trust-3 well, where Lanier was recently recompleted at an
initial 21 MMcfd. |
Marcellus shale Pennsylvania
30 MMcfd -7 wells
December 8, OGJ.com
Range Resources Corp., Fort Worth, said seven wells totaling 30 MMcfd from
the Marcellus shale are connected to Pennsylvania’s first large-scale gas
processing plant, operated by MarkWest Energy Partners LP. Range plans
to begin flowing more wells as two more gas processing plants are completed
next year (OGJ Online, Oct. 22, 2008). The company plans to enter 2009
with three horizontal rigs and boost that to six by the end of the year. It
expects yearend 2009 production to reach anet 80-100 MMcfed.
Talisman Energy Inc., Calgary, deferred a five-well Marcellus shale pilot
in New York pending environmental and regulatory reviews and shifted its focus
to Pennsylvania. The company’s Fortuna Energy Inc. unit holds almost
120,000 acres of state controlled land in north-central Pennsylvania and
is drilling a pilot in an area where it owns 19,200 net acres prospective
for development. It was completing its first operated horizontal well this
month. Talisman Energy’s holding totals 640,000 net acres in both states
in the emerging overpressured Marcellus play. It estimates gas in place in
the Marcellus at 20-100 bcf/sq mile at 2,500-6,000 ft. |
Marcellus Shale could hold
1,100 tcf
Source: http://www.platts.com 29-10-08
The gas potential of the Marcellus Shale may be as high as 1,100 tcf, well
above the 50 tcf previously forecast, the US's top academic authority on the
play said. "There's something really big in the Marcellus," Pennsylvania
State University professor Terry Engelder told an audience of oil and gas
executives at Platts' Appalachian Gas conference in Pittsburgh. "The Marcellus
is much bigger than the Barnett," Engelder said, adding that he based his
projection on early reports from Range Resources and Chesapeake Energy's initial
wells in the play. Engelder earlier estimated that the shale contained about
50 tcf of recoverable gas.
While he called Chesapeake's numbers "mildly optimistic," Engelder said
Range's numbers buttress his new forecast of more than 1 tcf of recoverable
gas from the shale play which extends from New York south through Pennsylvania
and into West Virginia. "It's bigger than the Barnett, Fayetteville, and
Woodford shales combined," he said. Getting that gas to market is another
problem, Engelder said. "The cost of land is going to scale to the price
of gas," he said.
Already, Pennsylvania landowners are reporting lower priced leasing deals
from exploration and production companies as the price of gas has fallen nearly
by half since June. Overlapping regulatory agencies present a further problem
for E&P companies, Tudor Pickering Holt Managing Director David Pursell
said. "There are guys who aren't entering this play because of regulation,"
he said.
The biggest regulatory uncertainty is the Susquehanna River Basin Commission,
a federal agency that controls water use in much of eastern Pennsylvania,
Pursell said. The commission only meets quarterly, and Pursell said that isn't
often enough to keep pace with the gas rush that's occurring in the state.
"Ultimately, the Marcellus will be developed, the economics are just too
large to ignore," Pursell said.
He said the cost to buy that gas in the ground was about $ 4/mm cf and
with the forward strip calling for gas at $ 10/mm cf, the profit potential
of the Marcellus is just too large for E&P companies to ignore.
"The Marcellus has all the economies of shale plays," he added. "Easy to
find, hard to produce." He said Tudor Pickering Holt is forecasting 2.6 bn
cfpd of production from the play by 2023. |
Marcellus Cabot Pennsylvania, 13 MMcf/d
Cabot Oil & Gas Corp. 12/8/2008
Cabot has announced that its Marcellus initiative in northeastern Pennsylvania
is gaining momentum and is currently producing over 13 Mmcfe per day. Most
recently, Cabot completed its first Marcellus horizontal well with a measured
depth of 8,925' and a horizontal leg at 2,000' using a six-stage frac. The
result was a 24-hour average initial production rate of 6.4 Mmcf per day.
"Adding this to our series of vertical wells, which have been turned in
line over the last five months and have a 30-day average IP of 750 Mcf per
day, has allowed Cabot to exceed our original year-end Marcellus production
target of six to nine Mmcf per day," said Dan O. Dinges, Chairman, President
and Chief Executive Officer. "We expect this to increase considerably over
the next few weeks as we have nine additional wells (six vertical and three
horizontal) ready to be completed or in the final stages of pipeline hookup."
To date, the Company has drilled 18 total wells in the field, four of these
as horizontal tests. Five rigs are currently working with plans to increase
to eight rigs in 2009. "Our 2008 program will be 16 vertical wells plus seven
horizontal wells," added Dinges. Cabot has four vertical wells and three horizontal
wells remaining to be drilled this year and will continue operations seamlessly
into 2009. Total well costs range between $1.3 million to $1.5 million for
a typical vertical well and $2.6 million to $2.9 million for a horizontal
well. The average depth of a vertical well is 7,200'; the average horizontal
leg is approximately 2,200'.
In terms of infrastructure, the Company has completed its first phase pipeline
build-out totaling 10 miles and has started up its first compressor with a
second unit on site and ready to be utilized once production volumes justify
the need. "We continue to actively secure rights of way and gain permits to
expand our pipeline infrastructure for our 2009 drilling program," commented
Dinges.
Other News
In other news, Cabot completed its first horizontal Berea well in southern
West Virginia. This well came on line at approximately 900 Mcf per day, from
a 1,600' lateral section. Early production rates suggest ultimate recovery
between 1.0 - 1.2 Bcfe from this zone at a finding cost of less than $1.50/Mcfe.
The Company has identified over 60 additional locations on the current acreage.
East Texas
"We continue to work with vendors to secure the frac sand for our completion
operations," stated Dinges. "Currently we expect the horizontal Haynesville/Bossier
shale at Minden and the deep vertical test at County Line, both to be fraced
in mid-December."
In east Texas, the Company is testing its first horizontal Haynesville
lime well. The Pinkerton 12H was drilled to a total depth of 14,407' with
a 3,100' horizontal section. It was stimulated with an eight-stage treatment
with 1.6 million pounds of proppant. It is too early to tell how this well
will perform as the company continues to flow back completion fluid. This
completion and others in the company have been delayed due to a lack of proppant
which seems to be an industry-wide problem.
|
Haynesville gas flows as high
as 28 MMcfd
By OGJ editors HOUSTON, Dec. 9
Three operators reported new horizontal completions in Jurassic Haynesville
shale at rates as high as 28.2 MMcfd of gas.
The three companies, Petrohawk Energy Corp. of Houston and Comstock Resources
Inc. and EXCO Resources Inc. of the Dallas area, plan much more activity in
the Haynesville in East Texas and Northwest Louisiana.
Petrohawk reported the 28.2 MMcfd rate at its Sample 9-1 in 9-14n-11w,
Red River Parish, La., about 12 miles south of Elm Grove gas field. The rate
came on a 30/64-in. choke with 7,100 psi flowing casing pressure. Petrohawk's
Brown 17-4 in 17-16n-11w, Bossier Parish, gauged 23.4 MMcfd on a 26/64-in.
choke with 7,700 psi FCP. And its Goodwin 9-5 in 9-16n-11w, Bossier Parish,
made 21.1 MMcfd on a 26/64-in. choke with 6,750 psi FCP. The company
plans to complete five more Haynesville shale wells by yearend 2009.
Initial flow rate is 9 MMcfd at Comstock's BSMC LA 7-1H well in Toledo
Bend North field, De Soto Parish. The flow came from a 4,300-ft lateral at
11,750 ft true vertical depth after a 10-stage frac. Comstock is running
another 10-stage frac at its Collins LA 15-1H well in Logansport field, also
in De Soto. It has a 4,200-ft leg at 11,350 ft. The company has a 22% interest
in the Gamble 24-1H well at Logansport, drilled to 11,800 ft TVD with a 3,950-ft
lateral. Comstock has drilled the vertical portion of two other Haynesville
wells. Bogue A-6H in Waskom field in Harrison County is to get a 4,000-ft
lateral, and Green 13H in Blocker field in Harrison County is to get a 3,700-ft
lateral. Comstock is drilling vertically at Headrick 1H and Hart 1H
in Logansport and Moneyham 7H in Longwood field. Each is due a 4,000-ft leg.
EXCO said its first Haynesville horizontal well, Oden 30H6 in De Soto Parish,
averaged 22.5 MMcfd on a 26/64-in. choke with 7,800 psi FCP. It has a 4,481-ft
lateral at 12,304 ft TVD. EXCO has two operated horizontal wells, one
vertical well, and two outside-operated horizontal wells in the play and plans
to drill 25 or more horizontal Haynesville wells in 2009. |
Petrohawk 3 New Haynesville Shale Wells 73 Mmcfe/d
HOUSTON, Dec. 9 /PRNewswire-FirstCall/
Petrohawk Announces Three New Haynesville Shale Wells Placed
on Production at a Combined Rate of 73 Mmcfe/d.
The Company expects to complete five additional Haynesville
Shale wells by the end of the year.
-- Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK)
has placed three additional Haynesville Shale wells on production at a combined
rate of 73 Mmcfe/d, one with the highest reported initial production rate
of any well in Petrohawk's history, as follows:
The Brown 17 #4 (69% W.I.),
located in Section 17-T16N-R11W, Bossier
Parish, Louisiana, was completed
on November 18 and produced at a rate
of 23.4 Mmcfe/d on a 26/64"
choke with 7,700# flowing casing pressure.
The Goodwin 9 #5 (97% W.I.),
located in Section 9-T16N-R11W, Bossier
Parish, Louisiana, was completed
on November 25 and produced at a rate
of 21.1 Mmcfe/d on a 26/64"
choke with 6,750# flowing casing pressure.
The Sample 9 #1 (100% W.I.)
is located in Section 9-T14N-R11W, Red
River Parish, Louisiana, approximately
12 miles south of Elm Grove
Field. It was completed on November
27 and produced at a rate of 28.2
Mmcfe/d on a 30/64" choke with
7,100# flowing casing pressure.
Petrohawk Energy Corporation is an independent energy company engaged in
the acquisition, production, exploration and development of natural gas and
oil with properties concentrated in Northwest Louisiana and East Texas (Haynesville
/ Bossier Shale and Cotton Valley), Arkansas (Fayetteville Shale), South Texas
(Eagle Ford Shale), Oklahoma and the Permian basin.
For more information contact Joan Dunlap, Vice President - Investor Relations,
at 832-204-2737 or jdunlap@petrohawk.com. For additional information about
Petrohawk, please visit our website at http://www.petrohawk.com. |
Range
Resources Reaches Production Milestone
Range Resources Corp. 12/2/2008
Range Resources has reached the 400 Mmcfe per day production milestone.
The Company currently anticipates that fourth quarter 2008 production will
be within its previous guidance of 400 to 405 Mmcfe per day. This represents
an 18% increase for the quarter and nearly a 20% increase for the year. This
will also represent Range's 24th consecutive quarter of sequential production
growth. The rising production is the result of the Company's successful drilling
program. All of Range's divisions have increased production for the year through
the drill bit.
Commenting on the announcement, John Pinkerton, Range's Chairman and CEO,
said, "Reaching 400 Mmcfe per day of production is a terrific milestone for
all of us at Range. The drilling program has been the principle driver for
our growth as we have focused on lower cost drilling versus higher cost acquisitions.
As a result, we have maintained our low cost structure, which is critical
in the current environment. Rising production, a low cost structure, hedges
in place covering approximately 60% of next year’s production and strong
liquidity position us well as we enter 2009." |
Haynesville $1.1 B Pipeline Expansion Regency Energy
Pipeline & Gas Journal Nov 2008
Regency Energy Partners LP plans to expand its pipeline system in north
Louisiana to bring natural gas from the Haynesville Shale — one of the most
active new natural gas plays in the United States. The $1.1 billion expansion
of the Regency Intrastate Gas System will provide 1.45 Bcf/d of new capacity
to handle expected increases in production from the region. Regency has obtained
letters of intent for long-term transportation agreements from anchor shippers
covering approximately 76% of the incremental capacity and is also seeing
strong demand for the remaining capacity.
The Haynesville expansion project includes looping the existing pipeline,
extending the system and adding new compression. Construction of the project
will be divided into two phases.
Phase one expects completion first half of 2009, adding 300 MMcf/d of capacity
once fully operational. Phase one will comprise $375 million of the total
cost of the project.
Phase two will add an incremental 1.15 Bcf/d and is expected to be online
by end 2009 and fully operational early 2010. Overall, the project will add
204 miles of pipeline, ranging from 24 to 42 inches, and 49,000 horsepower
of compression.
Regency also plans to expand some of its existing interconnections with
interstate pipelines and is exploring new intrastate and interstate market
options for its shippers. The system reaches across north Louisiana, from
Caddo Parish to Franklin Parish and will be expanded to the southwest into
Desoto Parish to interconnect with Regency’s Logansport gathering system.
Regency selected Gulf Interstate Engineering Company to provide engineering,
design and procurement services for the three compressor stations in northern
Louisiana, Cane Hill, Woodardville and Elm Grove. Gulf will also be responsible
for providing engineering, design and procurement services for four interstate
delivery-interconnects with Texas Gas, Trunkline, ANR and Columbia Gulf and
multiple receipt point interconnects with various producers. In addition,
Gulf will support Regency with scheduling and project controls services for
the project.
In other news, Gulf Interstate was awarded a contract by Consorcio Terminales
GMP - Oiltanking to perform a feasibility study and capital cost estimate
for the Poliducto Pisco Lima Ventanilla Project (PPLV). Specifically, Gulf’s
scope of work on the LPG pipeline and facilities includes the evaluation of
the pipeline route, development of preliminary route maps, development of
P&IDs, plot plans, one line diagrams, and a SCADA system architecture
diagram for five facility sites. The facility sites include pump stations,
metering and storage, truck-loading facilities and delivery meter stations. |
Marcellus Mid-Stream Pipeline Project by Superior Appalachian
Superior Appalachian To Build Mid-Stream Pipeline Projects
Pipeline & Gas Journal Nov 2008
A division of an Oklahoma company wants to lay natural gas lines in Centre
County, PA, partly in anticipation of an untapped supply of gas in the Marcellus
Shale region. Superior Appalachian Pipeline has been working to acquire the
rights-of-way for a line from property owners in areas including Burnside,
Snow Shoe and Curtin townships.
Chuck Davies, vice president of business development, said the company
opened an office in Canonsburg to look at places in Pennsylvania where gas
is constrained by capacity shortages in existing pipelines. The company is
also interested in the increased need for gas lines that could come from
the Marcellus Shale.
|
Fayetteville Express Pipeline JV $1.3 Billion Pipeline
Pipeline & Gas Journal Nov 2008
Kinder Morgan Energy
Partners, L.P. and Energy Transfer Partners, L.P. have entered into a 50/50
joint venture, Fayetteville Express Pipeline, LLC (FEP), to develop a new
pipeline. The 187-mile pipeline will originate in Conway County. AR, continue
eastward through White County, AR, and terminate at an interconnect with
Trunkline Gas Company in Quitman County, MS. The pipeline will have an initial
capacity of 2 Bcf/d. Pending necessary regulatory approvals, the approximately
$1.3 billion pipeline project is expected to be in service by late 2010
or early 2011. FEP has secured binding 10-year commitments of 1.575 MMDth/d
including 1.2 MMDth/d from Southwestern Energy Services, a unit of Southwestern
Energy Co., and 375,000 Dth/d with an option for an additional 125,000 Dth/d
from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy
Corp.
To gauge further shipper interest, FEP began a binding open season on Oct.
8 that ran through Nov 7. Depending on shipper support during the open season,
capacity on the proposed pipeline may be increased. |
Atlas to pursue New Albany
shale in Indiana
Oil& Gas Journal/Nov. 17, 2008
Atlas Energy Resources LLC, Pittsburgh, plans to drill more than 100 horizontal
wells to Devonian New Albany shale in southwestern Indiana by the end of 2009.
The company has acquired 114,000 net acres and has taken a farmout on 78,000
net acres from Aurora Oil & Gas Corp., Traverse City, Mich. The combined
transactions give Atlas rights to 284,000 largely contiguous gross acres
in the Illinois basin, mainly in Sullivan, Knox, Greene, Owen, Clay, and
Lawrence counties, Indiana.
Drilling is to start in 2008, with Atlas Energy using capital from its
syndicated oil and gas investment programs. The total acreage contains about
800 horizontal drilling locations.
The farmout requires that Atlas Energy drill at least 20 wells/year and
grants Aurora a right to participate for 25%. Aurora will receive a well
site fee for and overriding royalty interest in each well.
The acreage is in the northern “biogenic” part of the New Albany shale
play, where several operators have drilled more than 40 successful horizontal
wells, said Atlas Energy. “We have been studying the New Albany shale
for over 2 years and believe the predictable and statistical nature of its
development is a perfect fit for our investment programs,” said Atlas Energy
president and chief operating officer Richard D. Weber.
Overseeing Atlas Energy’s New Albany shale development will be the company’s
Antrim Shale operating team, led by Dick Redmond, president of Atlas Energy
Michigan LLC. The New Albany shale has many similarities to Michigan’s biogenic
Antrim shale, in which Atlas Energy is the largest and one of the lowest cost
operators.
Atlas Energy noted that New Albany is a blanket formation 100-200 ft thick
and 500-3,000 ft deep. Natural fracture patterns are low-angle in the Antrim
shale and vertical in the New Albany.
Atlas Energy reviewed more than 30 successful horizontal completions in
and near its acreage and observed an average estimated ultimate recovery
of 1 .3 bcf/well. Horizontal New Albany wells with 4,000-5,000-ft laterals
can be drilled and completed for $1.3 million.
Aurora Oil & Gas, through predecessors, has been working in the New
Albany play since 1994. Operator and majority owner until now of its 121,702-gross-acre
Wabash project in Clay, Greene, Owen, and Sullivan counties, it has drilled
13 wells. All may be considered productive, but all are shut-in awaiting connection
to pipeline and processing facilities. |
Albany Shale GTI Partners Recoverable Gas project
Pipeline & Gas Journal Nov 2008
GTI has entered into a multi-year program with the Research Partnership
to Secure Energy for America (RPSEA) to lead a field-based research consortium
focused on meeting U.S. natural gas demand and lowering costs for consumers.
The consortium is comprised of GTI and 14 participants including producing
companies Atlas Gas & Oil, Aurora Oil and Gas, BreitBurn Energy, CNX Gas
Corp, Inflection Energy, NGAS Resources, Noble Energy and Trendwell Energy
Corp.
The principal objective is to develop techniques and methodologies for
increasing the success rate and productivity of New Albany shale gas wells
to a level at which the otherwise noncommercial wells become commercially
viable. The consortium will be conducting joint research targeting the 10.5
Tcf of technically recoverable gas in the New Albany Shale formation, with
the overall goal of converting it to an economically recoverable resource.
|
Anadarko basin Upper Devonian
Woodford shale Oklahoma
Oil& Gas Journal/Nov. 17, 2008
A play for gas-condensate and oil in the fractured Upper Devonian Wood-ford
shale formation is emerging on the Oklahoma side of the Anadarko basin. The
Woodford shale, thought of until relatively recently as a source rock, has
developed into a considerable gas producing formation in the Arkoma basin
on the opposite side of the Nemaha ridge, and production is also emerging
in the Ardmore basin. Cimarex Energy Co.,
Denver, began assembling acreage about 18 months ago to drill the Woodford
as a primary objective in the Anadarko. Cimarex said the play holds potentially
1.5 to 2 tcf recoverable to the company.
Several other operators are believed to be pursuing or evaluating positions
as well. Cimarex amassed 50,000 acres in Woodford-prospective areas of central-western
Oklahoma and in late October completed the acquisition of a further 38,000
net acres from Chesapeake Energy Corp.
for $180 million. The acreage is in Blaine and Canadian counties. Only $5
million of that transaction went for reserves, Cimarex revealed. It was the
last large block to be acquired in its core area in the Woodford play, the
company said.
Linn Energy LLC, Houston,
announced the sale of its deep rights including the Woodford shale interval
in certain central Oklahoma acreage to an undisclosed buyer on Oct. 10 for
$229 million, subject to closing adjustments. That sale included no producing
assets, and Linn Energy retained the shallow rights.
Continental Resources Inc.,
Enid, said it held 111,000 net acres in early November 2008 in the Anadarko
Woodford shale.
Drilling progress
Cimarex, still leasing in the play, participated in 28 wells by late October;
16 completed and 12 still drilling or being completed. Drilling totals 31
wells by all operators, Cimarex said, and the other three wells were still
being drilled in late October. Continental Resources said it was drilling
two operated wells in the play as of Nov. 6. The company holds a mix
of acreage, some held by production from other formations.
Devon Energy Corp. and Western Oil & Gas Development
Corp., both of OK City are companies in the emerging play
Other companies appear to have HBP acreage and may be evaluating their
positions.
Cimarex looks for the average well to recover nearly 5 bcf on 160-acre
spacing with a 4,000-ft lateral. Wells with that lateral length have averaged
initial production rates of 5 MMcfd. Cimarex defines the Anadarko Woodford
as occurring at 11,000-16,000 ft, where it is 120-280 ft thick, has 3-9%
total organic carbon, good porosity and permeability, and gas in place of
145-195 bcf/sq mile. The Woodford represents “a big, multiyear drilling program
in a play we like,” said F.H. Merelli, chairman, chief executive officer,
and president of Cimarex. The company is already studying the desirability
of downspacing to 80 acres. Half of Cimarex's 88,000 net acres is held by
production from other formations, so the company is in control of development
timing rather than being governed by lease expiration deadlines. Well cost
could moderate slightly from the current $8.5 million to $9 million, Cimarex
said. The company said it was dropping five rigs in the Texas Panhandle,
but it expects to be running 9-11 rigs in the spring of 2009, up from five
operated rigs in late October 2008. While climbing learning curves on drilling
and completion techniques in the Anadarko Woodford shale, operators will
be deciding how far west they will be able to pursue the play given the economics.
The formation plunges well below 15,000 ft as it trends westward toward the
deep Anadarko basin trough.
|
Petrohawk Announces
New Shale Gas Field Discovery
Eagle Ford Shale Well Placed on Production at 9.1 Mmcfe/d
HOUSTON, Oct. 21 /PRNewswire-FirstCall/
Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK)
announced a significant new natural gas field discovery in the Eagle Ford
Shale in South Texas. This new field in La Salle County, Texas, was discovered
after extensive regional subsurface and seismic mapping, geochemical analysis
and petrophysical study. The Company has leased over 100,000 net acres in
what it believes to be the most prospective areas for commercial production
from the Eagle Ford Shale. The field is located immediately south of the
Stuart City Field, which is on the Edwards Reef Trend that extends across
South Texas.
"This discovery folds perfectly into our portfolio of unconventional resource
assets," said Dick Stoneburner, Chief Operating Officer. "Petrohawk's staff
has extensive experience in the acquisition and development of horizontal
plays as exhibited by our results in the Haynesville Shale and Fayetteville
Shale plays. Leveraging that expertise to uncover new opportunities like the
Eagle Ford Shale adds significantly to our playbook."
The discovery well, the STS #241-1H, was drilled to an approximate true
vertical depth of 11,300 feet during which extensive coring and open hole
logging was performed. An approximate 3,200-foot lateral was drilled and
subsequently fracture stimulated with over two million pounds of sand in
ten stages. The well was placed on production at a rate of 9.1 million cubic
feet of natural gas equivalent per day (7.6 million cubic feet of natural
gas per day and 250 barrels of condensate per day). A confirmation well,
the second well drilled on the project, the Dora Martin #1H, which is approximately
15 miles from the discovery well, has been drilled, cored and logged. The
quality of the Eagle Ford Shale in this well appears to be superior to that
found in the STS #241-1H. The Company is currently drilling the lateral on
this second well. A third well is expected to spud by mid-November.
Petrohawk expects drilling and completion costs for development wells to
range between $5 and $7 million. Development costs, including one rig that
will run continuously on the project, have already been included in the Company's
published 2008 and 2009 capital plans. The Company plans to access existing
gathering and transportation infrastructure, further improving lower overall
development costs.
Petrohawk is the operator and
owns 90% working interest in the project, with 10% owned by industry partners.
|
Louisiana-Mississippi
Encore and Tuscaloosa marine shale
Oil & Gas journal / Nov. 17, 2008
Encore Acquisition Co., Fort
Worth, is exploring for oil in the highly over-pressured Cretaceous Tuscaloosa
marine shale and has accumulated 210,000 net acres along the Louisiana-Mississippi
line east of the Mississippi River. The company mapped a silt in the
shale of sufficient integrity to drill a horizontal wellbore. It drilled and
cased to just beyond 17,000 ft measured depth the Weyerhaeuser-1 H, in irregular
section 60-ls-4e, in the northwestern corner of St. Helena Parish, La. Encore
Acquisition plans to attempt completion in the well’s 4,100-ft lateral, but
the attempt delayed 5 weeks due to the short supply of high-strength proppant.
The company, has drilled four horizontal wells in the play in 2008, took
a $26.3 million impairment charge on the first two, Richland Plantation-A
1 in East Feliciana Parish and Joe Jackson 4-13H in Amite County, Miss. |
Petrohawk’s production grows
25-35% by 2009
Oil & Gas Journal / Oct. 13, 2008
Petrohawk will emphasize development of nonproved locations
in its successful Haynesville and Fayetteville shale projects and expects
higher overall reserve growth potential. It projects that its production
will grow 25-35% through the drill-bit in 2009 from estimated 2008 production
of 305 MMcfd. The Haynesville shale sits 11,000 ft underground in East Texas
and northwestern Louisiana. The Fayetteville shale play is east of Little
Rock, Ark.
Petrohawk sliced its budget to $1 billion for drilling, comp1etions,
seismic exploration, and facilities, down from $1.5 billion previously. Officials
said the change affirms the company’s strong capitalization. The firm has
“no current plans or need to access the equity capital markets,” they said.
Petrohawk’s undrawn credit facility was increased to $1.1 billion from $800
million Sept. 10, 2008.
In addition, the company is looking to divest some conventional assets
in the Permian basin next year. These properties include interests in Waddell
Ranch, Sawyer, Jalmat, and TXL fields of West Texas and southeastern New Mexico.
The Permian basin properties currently produce 35 MMcfd of gas equivalent.
Even with the budget reduction, Petrohawk expects a production growth of
25-35% in 2009. It reaffirmed a third quarter guidance of 310-320 MMcfed.
Petrohawk Energy is engaged in the acquisition, production, exploration,
and development of natural gas and oil primarily north Louisiana, Arkansas,
East Texas, Oklahoma and the Permian Basin. |
Haynesville Shale flowing 16 MMcfd @ 6,400 psi
Questar Corp. 11/24/2008
Questar Exploration and Production Company has announced completion of
the company's first operated Haynesville Shale horizontal wells in Northwest
Louisiana. The Waerstad #3, located in Red River Parish, La. (Sec 1,
T14N, R12W) was placed on production on November 13, 2008, at an initial rate
of 16 million cubic feet of natural gas per day (MMcfd) on a 23/64 inch choke
with 6,400 pounds per square inch flowing casing pressure. Eight fracture
stimulation stages were pumped in the 3,234 foot horizontal lateral. Questar
E&P has a 100% working interest in the Waerstad #3 well.
The Wiggins 36H- #1, located in Bienville Parish, La. (Sec 36, T15N, R10W)
was placed on production on November 16, 2008, at an initial rate of 7.4 MMcfd
on a 22/64 inch choke with 5,450 pounds per square inch flowing casing pressure.
Nine fracture stimulation stages were pumped in the 3,455 foot horizontal
lateral. Questar E&P has a 62% working interest in the Wiggins 36H- #1
well.
Questar E&P is currently drilling two additional company-operated Haynesville
horizontal wells and is participating in four outside-operated Haynesville
horizontal wells that are in various stages of progress.
Questar E&P has approximately 31,000 net acres of Haynesville Shale
leasehold in the Elm Grove, Woodardville and Thorn Lake areas of Northwest
Louisiana. |
Marcellus New Technique
Higher Results-Atlas Energy
PITTSBURGH, Nov 24, 2008 Atlas Energy Resources
LLC (NYSE:ATN) ("Atlas Energy" or "the Company") Over the past several
weeks, Atlas Energy has successfully pioneered the use of a two-stage frac
design for five of its vertical wells as part of its Marcellus Shale drilling
program in southwestern Pennsylvania. Using this frac design, the Company
has averaged initial rates of production for 24 hours into a pipeline of
2.1 million cubic feet per day ("Mmcf/d"), more than double the Company's
historical average of approximately 1 Mmcf/d over 90 previous vertical completions
in its Marcellus program. Further, early results indicate that a well having
a two-stage frac exhibits a shallower decline rate than a well with a single
stage frac. Assuming these results continue, which are not assured, the Company
expects to realize sizable increased reserves and production per vertical
well drilled. The incremental cost of the two stage design over a single
stage design is approximately $125,000.
Atlas Energy is also pleased to report that it has successfully drilled
and cased its second horizontal well to the Marcellus Shale having a lateral
length of approximately 3,000 feet. The Company plans to complete this well,
located in Washington County, Pennsylvania, with an eight-stage frac. Atlas
has spud its third and fourth horizontal wells and is on track with its previously
announced plan to drill 12 horizontal wells in the next six months. These
horizontal wells are being drilled in an industry joint venture where Atlas
Energy will typically have a 50% working interest and is the operator.
"These results clearly demonstrate our growing expertise at Atlas Energy",
stated Richard D. Weber, President and Chief Operating Officer. "Using these
advanced techniques, we look forward to accelerating our growth in reserves
and production."
Atlas Energy Resources, LLC develops and produces domestic natural gas
and to a lesser extent, oil. Atlas Energy is one of the largest independent
energy producers in the Eastern United States. Atlas Energy sponsors and
manages tax-advantaged investment partnerships, in which it co-invests, to
finance the development of its acreage. For more information, visit Atlas
Energy's website at www.atlasenergyresources.com or contact Investor Relations
at bbegley@atlasamerica.com. |
XTO
$3.3 billion budget shale gas procssing
By OGJ editors HOUSTON, Nov. 21
XTO Energy Inc., Fort Worth, approved a 2009 capital budget for development
and exploration expenditures of $3.3 billion.
An additional $500 million has been budgeted for the construction of pipeline,
compression, and processing facilities. With these expenditures, it plans
to increase 2009 production volumes by 18% over 2008 levels.
"In these challenging times, the strength of our property base allows XTO
to continue to create shareholder value through volume growth and strong economic
margins," said Keith A. Hutton, XTO president. "With this managed growth
strategy, the company expects to average utilizing 90 drilling rigs for 2009.
Activities will include drilling 1,250 new wells and conducting 800 workover
events," he said.
During the year, the eastern region will be allocated $1 billion. The Barnett
shale will utilize about $800 million. The Arkoma basin and Midcontinent properties
will be allocated $500 million. The Bakken, Gulf Coast, and Offshore areas
will be allocated $350 million.
Programs in the Permian district are expected to utilize another $300 million.
The San Juan, Raton, Uinta, and Piceance basins combined will be allocated
$250 million. XTO will target $100 million for exploration events. |
Regulations could stifle
20 major US shale gas fields
Nick Snow OGJ.com Washington Editor WASHINGTON, DC, Nov. 24
Natural gas production from US shale plays such as the Marcellus shale
in New York, Pennsylvania, and West Virginia could double in the next 10
years and provide 25% of the nation's supply, a Natural Gas Supply Association
official said Nov. 21.
But NGSA Vice-Chairman Terrence L. Ruder, who also is senior vice-president
for Devon Energy Corp.'s marketing and mainstream division, also warned that
a windfall profits tax and new restrictive regulations could hurt that effort
a time when more gas will be needed to help meet clean air requirements mandated
by climate change legislation.
"What we've seen so far from shale fields is just the tip of the iceberg.
To facilitate a steady supply growth of gas from shale, we need a stable tax
and regulatory environment," Ruder told a Federal Energy Regulatory Commission
conference on the US gas infrastructure. He said shale developments
provide an estimated 6-8 bcfd of gas, or 10-12% of projected 2008 US demand.
Over the next 10 years, US shale gas production could double to 15-20 bcfd,
with total reserve estimates at 250-750 tcf of gas, he indicated.
Ruder said Devon has invested more than $10 billion in the Barnett shale
play in northern Texas. He estimated that the gas industry as a whole will
spend $150 billion to fully develop the Barnett shale play.
Twenty major US fields
Ruder noted that there are about 20 major shale fields across the US that
have the potential to or are currently producing gas, including the Bakken
play in North and South Dakota, the Woodford in eastern Oklahoma, the Haynesville
in East Texas and Louisiana, and the Green River Piceance basin play in Colorado.
"Shale developments are highly capital-intensive and a windfall profit
tax assessment now being discussed in Congress would directly and adversely
affect production," Ruder warned.
Another NGSA member, Clay Bretches, vice-president, minerals and marketing,
at Anadarko Petroleum Corp., expressed similar concerns. "I cannot emphasize
enough the importance of a stable regulatory environment. When exploration
and production companies expend billions of dollars on capital projects, they
can mitigate some of the risks stemming from price fluctuations, resource
requirements, and transportation constraints. But in absence of a transparent
and consistent regulatory environment, these projects may be delayed or worse
yet, never get off the drawing board," he said.
"What we need is regulatory certainty that not only benefits the economics
of the projects, but also provides adequate and on-time supply to consumers.
Make no mistake about it, regulatory uncertainty strongly impacts price volatility,"
Bretches said.
Ruder said shale developments have the potential to reshape the traditional
domestic gas supply mix and aid in the replacement of declining conventional
production. "Industry has proven it can develop shale plays safely. These
resources, however, will only partially satisfy the nation's growing demand
for natural gas, demand that will increase even more rapidly with any new
climate change policies," he said. |
U.S. Shale Gas Could Double
United Press International 11/21/2008
An energy association said Friday that production of natural gas from shale
deposits in the United States could be doubled over the next decade,
"if there is stable tax and regulatory
environment."
The Natural Gas Supply Association said its calculations indicated
that 25 percent of U.S. natural gas demand could be satisfied by the exploiting
shale beds located in Appalachia, the Barnett Permian Basin of Texas and other
areas of the nation. Shale gas is locked in the dense shale rock and
is released through a process known as hydraulic fracturing in which water
and sand are pumped into a well and build up enough pressure to fracture the
rock.
"What we've seen so far from shale fields is just the tip of the iceberg,"
Terry Ruder, vice chairman of the Natural Gas Supply Association, said in
a written statement. Rude said shale accounted for 6-8 billion cubic
feet per day of natural gas this year, about 10-12 percent of U.S. gas demand.
He estimated that production could reach 20 Bcfd over the next 10 years.
The promise of shale gas will
require some help from the federal government, however.
"To facilitate a steady supply growth of natural gas from shale,
we need a stable tax and regulatory environment," Ruder said. |
Appalachian expansion new
processing, CGT, MarkWest
Christopher E. Smith Pipeline Editor HOUSTON, Oct. 24
NiSource Inc. unit Columbia Gas Transmission Corp. and MarkWest Energy
Partners LP intend to jointly expand natural gas gathering and processing
services to support increased production volumes in the Appalachian basin
of central West Virginia.
The two companies also are discussing plans with several gas producers
to provide new gathering and processing services near Columbia's Cobb aggregation
system in Kanawha, Jackson, and Roane counties, W.Va.
The expansion of services includes MarkWest's previously announced expansion
of its Cobb gas processing plant, increasing total capacity to about 70 MMcfd
from the current 25 MMcfd by mid-2009. NGLs recovered at Cobb will continue
to be fractionated at MarkWest's Siloam fractionation, marketing, and storage
complex in South Shore, Ky., currently in the final stages of its own expansion.
Siloam can currently fractionate 600,000 gpd of propane, butane, and natural
gasoline and has 11 million gal of cavern propane storage.
Columbia will add horsepower to its existing Cobb compressor station and
install new field gathering and compression facilities to bring new production
to the Cobb processing plant. Further incremental additions of horsepower
and capacity remain possible as warranted by production increases.
These expansion plans follow an August 2008 announcement by the two companies
to expand similar services near Majorsville, W.Va., serving the northern panhandle
area of West Virginia and western Pennsylvania. |
StatoilHydro, Chesapeake join
in E&P pact
StatoilHydro has ventured into
unconventional gas opportunities arid gas shale development under an agreement
signed with Chesapeake Energy Corp., the largest US natural gas producer.
The companies have committed to jointly look for gas in China, Romania, and
Ukraine, said Statoil Executive Vice-Pres. Peter Mellbye in a conference call
with analysts and investors.
StatoilHydro has agreed to spend $3.38 billion for a 32.5% in
Chesapeake’s gas assets in the Marcellus shale region in Pennsylvania, West
Virginia and New York. StatoilHydro said $1.25 billion would be paid in cash,
and the outstanding $2.12 5 billion would constitute a 75% carry on drilling
and completion of wells during 2009-12.
“In order to earn this carry, Chesapeake is required to maintain a significant
level of drilling activity” the Stavanger-based major added.
The acreage covers 7,300 sq km and will add future recoverable
equity resources of 2.5-3 billion boe. StatoilHydro’s equity production from
the Marcellus shale gas play is expected to increase to a minimum 50,000 boe/d
in 2012 and at least 200,000 boe/d after 2020, with net positive cash flow
from 2013. Chesapeake plans to build upon its leases in the Marcellus shale
play with StatoilHydro having a right to a 32.5% interest in them.
“The agreement we have entered into with Chesapeake provides us with a
solid position in an attractive long-term resource base at competitive terms.”
said Helge Lund, president and chief executive officer of StatoilHydro. “This
is a significant step in strengthening our US gas position, building on our
existing capacity rights for the Cove Point LNG terminal, our gas trading
and marketing organization, and the gas producing assets in the US Gulf of
Mexico.”
The development program could support the drilling of 13,500-17,000 horizontal
wells over the next 20 years, using up to 50 drilling rigs. The expected cost
is estimated at $3.5 million/well, with an ultimate recovery of 560,000 boe/well.
The transaction is expected to close by yearend, 2008.
This announcement follows other recent deals that Chesapeake has struck
with Plains Exploration & Production Co. and BP America to raise funds
and develop its natural-gas holdings: Plains bought a 20% working interest
in its assets in the Haynesville shale in north Louisiana and East Texas
for $3.3 billion, and BP America acquired a 25% stake in its assets in the
Fayetteville shale for $1.9 billion. |
Range Resources Expands
Marcellus Shale Production
Range Resources 11/20/2008
Range Resources Corporation provided an update on its Marcellus Shale play.
Last month, Range and MarkWest Energy Partners, L.P. announced completion
of the first phase of the Marcellus Shale infrastructure. The initial phase
included gas gathering and compression, as well as Pennsylvania's first large-scale
gas processing facility. Since then, Range has been completing production
facilities and connecting previously drilled wells to the gas gathering system.
Currently, seven wells are tied into the gas processing facility and net sales
from these wells total 30 Mmcfe per day.
MarkWest is currently undertaking additional infrastructure development
which will serve to expand the gathering system and add gas processing capacity.
A cryogenic plant is expected to be online by the end of first quarter 2009,
increasing gas processing capacity to 60 Mmcf per day. By year-end 2009 or
early 2010, processing capacity is anticipated to be 180 Mmcf per day. As
additional gas processing capacity is completed, Range will turn on additional
wells. Range currently plans to enter 2009 with three horizontal rigs, increasing
to six rigs by the end of 2009. By year-end 2009, Range anticipates that production
will reach 80 to 100 Mmcfe per day, net to its interest.
John H. Pinkerton, Chairman and CEO of Range Resources, commented, "We
continue to make exciting progress in the Marcellus Shale play as production
rates are exceeding expectations. Our technical team is making excellent
headway in reducing drilling costs which is very important as we ramp up
our development activities. Having now transitioned from the testing phase
to the development phase, the Marcellus Shale play should greatly enhance
our future production, reserves and capital efficiency. Given its proximity
to the northeastern gas markets, the Marcellus Shale play is ideally located
to provide a new source of domestic, clean-burning natural gas for many years
to come. Importantly, during this period of economic uncertainty, the Marcellus
Shale play has the potential to add tens of thousands of new jobs and billions
of dollars of economic benefit." |
U.S. Shale Gas Could Double
United Press International 11/21/2008
An energy association said Friday that production of natural gas from shale
deposits in the United States could be doubled over the next decade,
"if there is stable tax and regulatory
environment."
The Natural Gas Supply Association said its calculations indicated
that 25 percent of U.S. natural gas demand could be satisfied by the exploiting
shale beds located in Appalachia, the Barnett Permian Basin of Texas and other
areas of the nation. Shale gas is locked in the dense shale rock and
is released through a process known as hydraulic fracturing in which water
and sand are pumped into a well and build up enough pressure to fracture the
rock.
"What we've seen so far from shale fields is just the tip of the iceberg,"
Terry Ruder, vice chairman of the Natural Gas Supply Association, said in
a written statement. Rude said shale accounted for 6-8 billion cubic
feet per day of natural gas this year, about 10-12 percent of U.S. gas demand.
He estimated that production could reach 20 Bcfd over the next 10 years.
The promise of shale gas will
require some help from the federal government, however.
"To facilitate a steady supply growth of natural gas from shale,
we need a stable tax and regulatory environment," Ruder said. |
Range Resources Expands
Marcellus Shale Production
Range Resources 11/20/2008
Range Resources Corporation provided an update on its Marcellus Shale play.
Last month, Range and MarkWest Energy Partners, L.P. announced completion
of the first phase of the Marcellus Shale infrastructure. The initial phase
included gas gathering and compression, as well as Pennsylvania's first large-scale
gas processing facility. Since then, Range has been completing production
facilities and connecting previously drilled wells to the gas gathering system.
Currently, seven wells are tied into the gas processing facility and net sales
from these wells total 30 Mmcfe per day.
MarkWest is currently undertaking additional infrastructure development
which will serve to expand the gathering system and add gas processing capacity.
A cryogenic plant is expected to be online by the end of first quarter 2009,
increasing gas processing capacity to 60 Mmcf per day. By year-end 2009 or
early 2010, processing capacity is anticipated to be 180 Mmcf per day. As
additional gas processing capacity is completed, Range will turn on additional
wells. Range currently plans to enter 2009 with three horizontal rigs, increasing
to six rigs by the end of 2009. By year-end 2009, Range anticipates that production
will reach 80 to 100 Mmcfe per day, net to its interest.
John H. Pinkerton, Chairman and CEO of Range Resources, commented, "We
continue to make exciting progress in the Marcellus Shale play as production
rates are exceeding expectations. Our technical team is making excellent
headway in reducing drilling costs which is very important as we ramp up
our development activities. Having now transitioned from the testing phase
to the development phase, the Marcellus Shale play should greatly enhance
our future production, reserves and capital efficiency. Given its proximity
to the northeastern gas markets, the Marcellus Shale play is ideally located
to provide a new source of domestic, clean-burning natural gas for many years
to come. Importantly, during this period of economic uncertainty, the Marcellus
Shale play has the potential to add tens of thousands of new jobs and billions
of dollars of economic benefit." |
StatoilHydro,
Chesapeake join in E&P pact
OGJ.com November
17 2008
StatoilHydro has ventured into unconventional gas opportunities
and gas shale development under an agreement signed with Chesapeake Energy
Corp., the largest US natural gas producer. The companies have committed
to jointly look for gas in China, Romania, and Ukraine, said Statoil Executive
Vice-Pres. Peter Mellbye in a conference call with analysts and investors.
StatoilHydro has agreed to spend
$3.38 billion for a 32.5% in Chesapeake’s gas assets in the Marcellus shale
region in Pennsylvania, West Virginia and New York. StatoilHydro said $1.25
billion would be paid in cash, and the outstanding $2.125 billion would constitute
a 75% carry on drilling and completion of wells during 2009-12.
“In order to earn this carry, Chesapeake is required to maintain
a significant level of drilling activity” the Stavanger-based major added.
The acreage covers
7,300 sq km and will add future recoverable equity resources of 2.5-3 billion
boe. StatoilHydro’s equity production from the Marcellus shale gas play is
expected to increase to a minimum 50,000 boe/d in 2012 and at least 200,000
boe/d after 2020, with net positive cash flow from 2013. Chesapeake plans
to build upon its leases in the Marcellus shale play with StatoilHydro having
a right to a 32.5% interest in them.
“The agreement we have entered into with Chesapeake provides
us with a solid position in an attractive long-term resource base at competitive
terms.” said Helge Lund, president and chief executive officer of StatoilHydro.
“This is a significant step in strengthening our US gas position, building
on our existing capacity rights for the Cove Point LNG terminal, our gas trading
and marketing organization, and the gas producing assets in the US Gulf of
Mexico.”
The development program could support the drilling of 13,500-17,000 horizontal
wells over the next 20 years, using up to 50 drilling rigs. The expected cost
is estimated at $3.5 million/well, with an ultimate recovery of 560,000 boe/well.
The transaction is expected to close by yearend, 2008.
This announcement follows other recent deals that Chesapeake has struck
with Plains Exploration & Production Co. and BP America to raise funds
and develop its natural-gas holdings: Plains bought a 20% working interest
in its assets in the Haynesville shale in north Louisiana and East Texas
for $3.3 billion, and BP America acquired a 25% stake in its assets in the
Fayetteville shale for $1.9 billion. |
Marcellus Gas estimates
20-100 bcf/sq mile Pennsylvania
By OGJ editors
HOUSTON, Nov. 19 -- Talisman Energy Inc., Calgary, deferred a five-well
Marcellus shale pilot in New York pending environmental and regulatory reviews
and shifted its focus to Pennsylvania.
The company's Fortuna Energy Inc. unit holds almost 120,000 acres of state
controlled land in north-central Pennsylvania and is drilling a pilot in an
area where it owns 19,200 net acres prospective for development. It was completing
its first operated horizontal well this month.
Talisman Energy's holding totals 640,000 net acres in both states in the
emerging overpressured Marcellus play. It estimates gas in place in the Marcellus
at 20-100 bcf/sq mile at 2,500-6,000 ft. |
Pennsylvania Shale; net sales 30 MMcfed
from seven wells
By OGJ editors
HOUSTON, Nov. 20 -- Range Resources Corp., Fort Worth, said its net sales
from the Marcellus shale in Pennsylvania reached 30 MMcfed from seven wells.
The wells are connected to the state's first large-scale gas processing
plant, operated by MarkWest Energy Partners LP.
Range plans to begin flowing more wells as gas processing capacity is completed
next year (OGJ Online, Oct. 22, 2008).
The company plans to enter 2009 with three horizontal rigs and boost that
to six by the end of the year. It expects yearend 2009 production to reach
a net 80-100 MMcfed. |
Kentucky Shale Gas Play Reports
Development
Gale Force Petroleum Inc. 11/19/2008
Gale Force has announced further interim results from its initial "Phase
1" development program on its Kentucky Appalachian Shale Gas Property.
Property will recover capital cost payback in less than 2
years with NYMEX at a constant $7.00 per Mcf, with a prospective internal
rate of return greater than 50%.
The Corporation has now completed 5 of the 9 wells on the property that
had never been completed, focusing primarily on stimulating the organically
rich hydrocarbon-bearing intervals within the Devonian Shale source rock
using fracture stimulation. The Corporation has obtained test results from
the 5 wells, which demonstrate that an average vertical well drilled on the
Kentucky
On September 24, 2008, the Corporation announced that it had re-entered
and started natural gas production from 4 of 9 existing wells on the Kentucky
Property that had already been completed. The Corporation will now tie-in
the remaining 5, newly completed wells.
The recent workover and completion program has proven that there is consistent
natural gas potential across the Kentucky Property, confirming that there
is low-risk drilling for the Devonian Shale target. There are more than 200
potential drilling locations adjacent to the existing infrastructure, which
means that the Kentucky Property is an excellent candidate for a low-cost,
multi-well drilling program designed to generate cash early in the project
development and increase the net present value of the reserves on the property.
"These are great results, which strongly suggest that the Kentucky Property
can create tremendous economical value if developed on a larger scale," said
Michael McLellan, President and CEO. "These results are in line with what
we told investors they could expect when we acquired the prospect."
The Kentucky Property was acquired by the Corporation on July 27, 2008
and included nine existing wells on the 22,000 acres of leased land with
ready access to market via existing pipeline infrastructure. Subject to new
financing, the Corporation will also drill and core additional wells on the
Kentucky Property and attempt alternative exploitation techniques such as
horizontal drilling, underbalanced drilling and open-hole completions, all
of which could improve the development template for the Kentucky Property,
permitting the Corporation to accelerate recovery of the gas resource and
create greater net asset value of reserves. |
Atlas
Energy’s Marcellus program delivers 60 MMcfd in
Pennsylvania Oil & Gas Journal
/ Oct. 20, 2008
Atlas Energy Resources
LLC, Philadelphia, is the largest producer of gas from Devonian Marcellus
shale in the Appalachian basin and has drilled more than 80 wells, almost
all of them vertical, the company said in a webcast Oct 8.
A sweet spot in the emerging play occurs in the same area as the company’s
gas gathering system, and Atlas Energy is moving 60 MMcfd, said Richard D.
Weber, president and chief operating officer. The company is expanding the
system’s capacity to 150 MMcfd by the end of 2008 and 250 MMcfd by the end
of 2009 from the present 120 MMcfd.
Atlas Energy previously said it could ultimately recover 4 to 6 tcf of
gas from the Marcellus on its properties mostly in southwestern Pennsylvania
(OGI, Mar. 3,2008, p.40).
The play falls in the midst of Atlas Energy’s historic acreage position.
It controls 580,000 acres, including 280,000 acres in a sweet spot in the
play in southwestern Pennsylvania.
The initial 24-hr flow rate has averaged 1 MMcfd, and the company assigned
average reserves of 1 bcf/ well. Initial flows have ranged from 300 Mcfd to
3.6 MMcfd.
Atlas Energy, which claims to be advanced in its understanding of the Marcellus
reservoir, said it has lately eliminated many of the low-end wells. It expects
the play to be developed with horizontal wells and has drilled one horizontal
penetration which was a success although costs were unacceptably high.
The company plans to drill four horizontal wells this fall in a 50-50 joint
venture in Washington County, Pa., offsetting acreage held by Range Resources
Corp., Fort Worth. The Marcellus in this area is lower pressured and less
geologically complex than in the areas Atlas Energy has drilled thus far.
The company plans to have 150 vertical wells on production by mid-2009
and by then expects to be able to assess whether to begin a bias toward horizontal
wells, Weber said.
It does not believe the Marcellus play will be productive continuously
across its entire extent (see map. OGI, Oct. 6, 2008, p.50). It sees another
sweet spot in northeastern Pennsylvania in Sullivan and Lycoming counties,
where little infrastructure exists.
|
Texas shale gas has
large reserves
11/19/08 houston.bizjournals.com
Gas shale plays will dominate future investment in oil and gas in Texas,
predicts Renato Bertani, president and CEO of Thompson & Knight Global
Energy Services LLC.
Since onshore oil and gas production from conventional sources has been
declining and will likely continue to decline, gas from unconventional sources
such as gas shale, coal bed methane and tight sands will drive supply growth
in the future. Of these, gas shale will be the most important source in Texas.
“Some companies have been very aggressive in securing acreage,” he noted at
a recent seminar for the firm’s clients.
The gas, trapped in micro-fractures in layers of shale, is more difficult
and expensive to produce than gas from conventional wells. But better technology
and, more importantly, rising prices for natural gas, have made it potentially
profitable.
“When gas is at $5 per Mcf (1,000 cubic feet) and above, these plays can
work,” says Bertani. Gas is now at $7 per Mcf.
He expects that the price will continue to rise, and that fossil fuels
in general will continue as the prevailing source of energy in the foreseeable
future.
Natural gas is now about half the price of oil on an energy equivalent
basis, in large part because gas is more difficult to move around. Acknowledging
that making price projections is very risky, he nonetheless expects that with
the growing availability of liquefied natural gas, gas prices will approach
oil equivalency, about $14 per Mcf, within four or five years. “This
resource will be more valuable over time,” he asserts. “Now is the time to
establish a strong acreage position.” Barnett Shale
Texas is blessed with large deposits of gas shale, left behind by vast
ancient seas that once covered most of the Central U.S. They laid down sedimentary
layers filled with organic material that settled into shales and fractured
many times, leaving gas trapped in the fractures. In many places, shales are
a caprock. In the case of gas shale they act as a source rock. In some places
the gas forms hot spots that can support clusters of producing wells.
Although Texas and Louisiana may seem to have been pored
over and drilled for decades, large reserves of gas shale remain to be tapped.
Most of the good wells in the state are in the Barnett shale, west of Dallas/Fort
Worth. The wells drilled in the rest of the state have mixed results. The
Barnett shale field has an estimated 50 trillion cubic feet of remaining reserves.
Other areas in Texas also have significant reserves.
Gas shale wells are drilled down to the target formation and then horizontally
along the layer of shale. The wells must be stimulated by hydraulic fracturing
operations. Fracing forces fluid at high pressure forced out into the formation.
The fluid contains spheres of aluminum oxide (or another proppant) which keep
the fractures open and allow gas to flow. The process results in wells
with high initial production that deplete quickly, usually in the first three
years, “maybe 10 years if you are in a hotspot,” says Bertani.
Rule of capture
A major legal issue with respect to fracing operations was recently decided
by the Texas Supreme Court, in Coastal Oil & Gas Corp. vs. Garza Energy
Trust. Garza sued Coastal for trespass, alleging that Coastal’s fracing of
its well on neighboring acreage had caused gas from Garza’s acreage to migrate
and be produced from Coastal’s well. At trial, Garza won on all counts and
was awarded $15 million in total damages, some of which were reduced by the
trial court.
Coastal argued that the rule of capture precluded Garza’s recovery. The
rule, which is well-settled law in Texas, gives a mineral rights owner title
to the oil and gas produced from a lawful well bottomed on his property,
even if the oil and gas flowed to the well from beneath another owner’s tract.
Garza claimed that the rule of capture did not apply because fracing was an
unnatural means of causing the gas to migrate to the property of another,
and claimed there was no difference between producing gas from another’s property
by means of fracing and producing gas from a slant well that bottoms under
the property of another, which is illegal.
The court affirmed the rule of capture, giving Coastal title to the gas
even if it had flowed to Coastal’s well from Garza’s tract, on grounds the
drained owner already has full recourse (he can drill his own well or apply
for pooling) and because changing the rule would usurp power of the Texas
Railroad Commission to regulate oil and gas. The court recognized that fracing
operations are essential to development of tight sands and gas shale plays
in Texas, specifically referencing the Barnett shale, and that some drainage
from fracing is virtually unavoidable.
The Coastal decision was long-awaited, and settled some
important issues, but questions remain. The court did not decide the broader
issue of whether fracing operations constitute trespass. “It’s not
really a great decision for the industry,” says Greg Curry, a litigator in
Thompson & Knight LLP’s Dallas office. “Now your lessor can sue you for
not preventing drainage.”
Charles Sartain of Looper, Reed & McGraw PC points out that the decision
could have a potentially adverse effect both in traditional areas of production
and in urban areas that will experience unprecedented mineral development
activity. “It is almost certain that this matter will continue as a
source of discussion, debate and litigation,” he says.
|
Unconventional gas spurs
EnCana’s output
Oil & Gas journal / Nov. 3,
2008
EnCana Corp. said its company wide natural gas production was up 8% to
3.9 bcfd in the quarter ended Sept.30 on a gain of 16% in its North American
unconventional gas plays.
East Texas output averaged 340 MMcfd, up 135% from the same quarter a year
ago, due to new wells coming on production and a 2007 acquisition that doubled
EnCana’s interest in the Jurassic Deep Bossier
play.
EnCana’s US gas production was up 24% on drilling and operational success
in the Fort Worth and Piceance basins and
Jonah field in Wyoming.
In Canada, coalbed methane, Cutbank Ridge,
and Bighorn increased production by 23%, partly offset by natural declines
from conventional properties, resulting in an overall 16% gain in the Canadian
Foothills division.
EnCana added 25,000 net acres in North Louisiana in the quarter, bringing
its Haynesville shale position to
400,000 net acres of land plus 63,000 net acres of mineral rights. EnCana
and its partner Shell Exploration & Production Co. have an industry-leading
land position in the area, where they are running six rigs and will target
drilling and completion of the first well in the mid-Bossier shale in the fourth quarter.
EnCana holds more than 700,000 acres in the Montney play in Northeast British
Columbia and northwestern Alberta, and EnCana and Apache Corp. have completed
seven wells this year in the Horn River basin shale play One of the most recent
wells averaged almost 8 MMcfd in the first 30 days. |
WVa. Appalachian Basin gas
expansion
Oil & Gas Journal / Nov. 3,
2008
NiSource Inc. unit Columbia Gas Transmission Corp., and Mark-West Energy
Partners LP intend to jointly expand natural gas gathering and processing
services to support increased production volumes in the Appalachian basin
of central West Virginia.
The two companies also are discussing plans with several gas producers
to provide new gathering and processing services near Columbia’s Cobb aggregation
system in Kanawha, Jackson, and Roane counties, WVa.
The expansion of services includes MarkWest’s previously announced expansion
of its Cobb gas processing plant, increasing total capacity to about 70 MMcfd
from the current 25 MMCM by mid-2009. NGLs recovered at Cobb will continue
to be fractionated at MarkWest’s Siloam fractionation, marketing, and storage
complex in South Shore. Ky., currently in the final stages of its own expansion. |
Huron shale Virginia horizontal
wells: Range Resources
Oil & Gas Journal / Nov. 3, 2008
Range Resources Corp., Fort
Worth, completed drilling its fifth horizontal well to Devonian Huron shale
in Nora field in southwestern Virginia.
The company, which says Huron
produces gas from 107 vertical wells in the field, estimated the formation’s
net reserve potential at Nora from horizontal drilling to 8-1.5 tcf.
The four horizontal
Huron shale wells averaged initial production of 1.1 MMcfd, averaged $1.7
million/well, and continue to produce in line with expectations, the company
said.
The company
noted that the Huron is thicker and higher pressured at Nora than in Kentucky.
Range Resourcea plans to drill five
more Huron shale wells and two horizontal Berea wells by the end of
2008.
|
MARCELLUS SHALE GAS
parts of three eastern US states,
a new opportunity
Atlas Energy Resources, LLC., Nov 10, 2008
The Marcellus shale in the Appalachia
basin extends over several states, although most wells drilled to date have
been in Pennsylvania.
It says Marcellus production has been minimal to date because
of the need to expand the existing infrastructure to accommodate the high-pressure
gas that the gas transportation system in Appalachia cannot at this time handle.
Most companies have so far drilled mostly vertical wells to
delineate the play, but the study expects horizontal wells to be the primary
means for developing the formation.
The Marcellus shale, which extends
575 miles across parts of three eastern US states, is thought to hold as much
as 500 tcf of natural gas, about 50 tcf of which is considered recoverable.
The area is bringing producers, landowners, and state and local officials
to address water use and other questions.
The Marcellus shale deep-gas formation also is bringing the
oil and gas industry into parts of Pennsylvania, New York, and West Virginia
for the first time. Producers have responded with aggressive outreach efforts.
“We have been meeting with individual groups about the Marcellus
play for some time,” said Charlie Burd, executive director of the Independent
Oil & Gas Association of West Virginia (IOGA of WV) in Charleston. “We
have been to several places in eastern West Virginia where this development
will take place because it lies in a formation that hasn’t been produced and
a part of the state that hasn’t had a lot of oil and gas exploration, Burd
said, adding, “So there’s more concern, both positive and negative, from
those constituents. Residents and royalty owners where there has been shallow
drilling are more familiar with the process of exploring and producing natural
gas and oil.”
State regulators also have responded. “We have experienced here
in Pennsylvania what may be a relatively unprecedented land rush,” said J.
Scott Roberts, deputy for mineral resources management in Pennsylvania’s
Department of Environmental Protection. “There are now several million acres
of private land which have been leased for Marcellus shale development, including
78,000 acres of state forest land where bids were put out in September,” Roberts
said.
Atlas_Energy_Applachian_Basin.jpg
“Pennsylvania’s traditional oil and gas production has been in the western
quarter of the state,” Roberts told OGJ during an Oct. 28 telephone interview.
“The Marcellus exists in sort of an arc, starting in the same portions to
the south but extending north and east, including all of our northern tier
counties to the Delaware River. Those counties haven’t seen any oil and gas
production because the opportunities haven’t existed,” he said.
EOG and Seneca
Resources Corp Pennsylvania
Devonian Marcellus shale
trend;
By OGJ editors HOUSTON, Nov. 7
Seneca Resources Corp., Buffalo, NY, bid successfully on 24,000 acres on
four large blocks in the Devonian Marcellus shale trend in Pennsylvania. The
leases, in Lycoming and Tioga counties, Pa., have 10-year primary terms and
are incremental to the 425,000 acres highgraded in this play. Meanwhile, Seneca
and EOG Resources Inc. modified the terms of their Marcellus shale joint
venture to require EOG to select all prospect acreage by March 2009. The
change will more quickly free up the nonselected acreage and allow Seneca
further flexibility to evaluate, explore, and develop the remaining lands
independently or with other partners.
Atlas Energy Marcellus shale 90 wells = 25 MMcfd into pipeline: Cumulative production
exceeds 4 bcf
By OGJ editors HOUSTON, Oct. 31
Atlas Energy Resources LLC, Pittsburgh, said it has 90 wells, some of which
have been on line for 2 years, producing a combined 25 MMcfd of gas into a
pipeline from Devonian Marcellus shale in Pennsylvania.
Cumulative production exceeds 4 bcf, making Atlas Energy the largest Marcellus
producer (OGJ Online, Oct. 8, 2008).
The last 13 vertical Marcellus completions have averaged an initial 1.3
MMcfd, and one vertical well in Fayette County came on at 3.6 MMcfd and has
produced 132 MMcf in 60 days.
The company plans to drill 32 vertical wells between next week and Mar.
31, 2009, and 75 more vertical wells the rest of 2009. It is also drilling
12 horizontal wells by next Mar. 31 as operator with 50% working interest
and 12 more horizontals with 100% by the end of 2009.
Cabot Oil & Gas Corp.,
Northeastern Pennsylvania Devonian Marcellus shale averaging 4-5 MMcfd from 5 vertical wells
By OGJ editors HOUSTON, Oct. 30
Cabot Oil & Gas Corp., Houston, is averaging 4-5 MMcfd of gas from
five vertical Devonian Marcellus shale producing wells in northeastern Pennsylvania.
The company expects to exceed its goal of producing 6-9 MMcfd by the end
of 2008. Cabot completed its first horizontal well, which will be on line
shortly, with only three of six planned fracs. The company will run the other
three fracs in a few weeks. Two more horizontal wells are cased awaiting completion,
and five vertical wells are in various stages of completion, all of which
are expected to be flowing to sales by yearend. Cabot Oil & Gas
Corp., Houston, set a 2009 capital budget of $450 million, dedicated to its
Pennsylvania Marcellus and East Texas Haynesville/Bossier drilling programs.
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Chesapeake Energy Corporation
Announces Marcellus Shale Joint Venture
International Unconventional Natural
Gas Exploration Alliance with StatoilHydro
OKLAHOMA CITY--(BUSINESS WIRE)--Nov. 11, 2008
Chesapeake Energy Corporation (NYSE:CHK) today announced the execution
of an agreement for a joint venture with StatoilHydro (NYSE:STO, OSE:STL)
whereby StatoilHydro will acquire a 32.5% interest in Chesapeake's Marcellus
Shale assets in Appalachia for $3.375 billion, leaving Chesapeake with a
67.5% working interest. The assets include approximately 1.8 million net
acres of leasehold, of which StatoilHydro will own approximately 0.6 million
net acres and Chesapeake will own approximately 1.2 million net acres.
StatoilHydro will pay $1.25 billion in cash at closing and will pay a further
$2.125 billion from 2009 to 2012 by funding 75% of Chesapeake's 67.5% share
of drilling and completion expenditures until the $2.125 billion obligation
has been funded. Chesapeake plans to continue acquiring leasehold in the Marcellus
Shale play and StatoilHydro will have the right to a 32.5% participation in
any such additional leasehold.
Additionally, Chesapeake and StatoilHydro have agreed to enter into an
international strategic alliance to jointly explore unconventional natural
gas opportunities worldwide. Closing of the transaction and strategic alliance
is anticipated to occur by year-end 2008.
Helge Lund, President and CEO of StatoilHydro, stated, "I am pleased that
we today have made a strategically important move by joining forces with Chesapeake,
which is the leading U.S. natural gas player. We are establishing a strong
platform for further developing our gas value chain business and growing
our position in unconventional gas worldwide. The agreement we have entered
into with Chesapeake provides us with a solid position in an attractive long-term
resource base under competitive terms. Additionally, this deal adds a major
building block to the gas value chain position we have established in the
U.S., the world's largest and most liquid gas market. This is a significant
step in strengthening our U.S. gas position, building on our existing capacity
rights for the Cove Point LNG terminal, our gas trading and marketing organization
and the gas producing assets in the Gulf of Mexico."
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We
are honored to establish a business relationship with StatoilHydro and are
excited about the mutually beneficial nature of our transaction with them.
We believe this transaction creates substantial value for both companies and
unique opportunities for international growth with one of the leading international
oil and gas companies. Jointly we can export our world class unconventional
natural gas technology for further long-term growth.
"Chesapeake has now completed three shale joint ventures that collectively
value Chesapeake's Haynesville, Fayetteville and Marcellus Shale assets (before
the joint ventures) at approximately $34 billion. Through these transactions,
Chesapeake sold a 20% working interest in its Haynesville Shale assets to
Plains Exploration & Production Company (NYSE:PXP) for $3.3 billion (thereby
retaining an 80% working interest valued at $13.2 billion), a 25% working
interest in its Fayetteville Shale assets to BP America (NYSE:BP) for $1.9
billion (thereby retaining a 75% working interest valued at $5.7 billion)
and now has agreed to sell a 32.5% working interest in its Marcellus Shale
assets to StatoilHydro for $3.375 billion (thereby retaining a 67.5% working
interest valued at $7.0 billion). The total consideration to CHK from these
sales has been approximately $8.575 billion, of which approximately $4.0 billion
has been (or will be) in cash and approximately $4.575 billion is in drilling
and completion cost carries. Furthermore, CHK retains the remaining ownership
percentages of the joint ventures that have been valued at approximately $26
billion, or over $40 per share of value from just these three shale joint
venture transactions. These joint ventures clearly demonstrate the enormous
value of Chesapeake's shale natural gas assets and the unique capability of
our organization to develop them."
Chesapeake was advised on the transaction by Jefferies Randall & Dewey
of Houston, Texas.
Chesapeake Energy Corporation is the largest producer of natural gas in
the U.S. Headquartered in Oklahoma City, the company's operations are focused
on exploratory and developmental drilling and corporate and property acquisitions
in the Fort Worth Barnett Shale, Fayetteville Shale, Haynesville Shale, Mid-Continent,
Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf
Coast and Ark-La-Tex regions of the United States. Further information is
available at www.chk.com.
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Atlas to pursue New Albany shale in Indiana
By OGJ editors HOUSTON, Oct. 30
Atlas Energy Resources LLC, Pittsburgh, plans to drill more than 100 horizontal
wells to Devonian New Albany shale in southwestern Indiana by the end of 2009.
The company has acquired 114,000 net acres and has taken a farmout on 78,000
net acres from Aurora Oil & Gas Corp., Traverse City, Mich. The combined
transactions give Atlas rights to 284,000 largely contiguous gross acres in
the Illinois basin, mainly in Sullivan, Knox, Greene, Owen, Clay, and Lawrence
counties, Indiana. Drilling is to start in 2008, with Atlas Energy using
capital from its syndicated oil and gas investment programs. The total acreage
contains about 800 horizontal drilling locations. The farmout requires that
Atlas Energy drill at least 20 wells/year and grants Aurora a right to participate
for 25%. Aurora will receive a well site fee for and overriding royalty interest
in each well.
The acreage is in the northern "biogenic" part of the New Albany shale
play, where several operators have drilled more than 40 successful horizontal
wells, said Atlas energy. "We have been studying the New Albany shale for
over 2 years and believe the predictable and statistical nature of its development
is a perfect fit for our investment programs," said Atlas Energy president
and chief operating officer Richard D. Weber.
Overseeing Atlas Energy's New Albany shale development will be the company's
Antrim Shale operating team, led by Dick Redmond, president of Atlas Energy
Michigan LLC. The New Albany shale has many similarities to Michigan's biogenic
Antrim shale, in which Atlas Energy is the largest and one of the lowest cost
operators.
Atlas Energy noted that New Albany is a blanket formation 100-200 ft thick
and 500-3,000 ft deep. Natural fracture patterns are low-angle in the Antrim
shale and vertical in the New Albany. Atlas Energy reviewed more than 30 successful
horizontal completions in and close to its acreage and observed an average
estimated ultimate recovery of 1.3 bcf/well. Horizontal New Albany wells
with 4,000-5,000-ft laterals can be drilled and completed for $1.3 million.
Aurora Oil & Gas New Albany shale in Indiana Aurora Oil & Gas, 13 wells All considered
productive, shut-in awaiting connection to pipeline and processing facilities.
, through predecessors, has been working in the New Albany play
since 1994. Operator and majority owner until now of its 121,702-gross-acre
Wabash project in Clay, Greene, Owen, and Sullivan counties, it has drilled
13 wells. All may be considered productive, but all are shut-in awaiting connection
to pipeline and processing facilities.
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Barnett Fort Worth basin 8,416 wells 19 counties 3.8 bcfd
1st quarter 2008 from .219 bcfd 2000 6-7 bcfd by 2013.
Development activity continues to evolve with part of the current activity
in urban sites such as Fort Worth and the Dallas-Fort Worth airports.
The study notes that as of Aug. 18, 2008, the Barnett had 8,416 gas wells
drilled in 19 counties. Production had increased to 3.8 bcfd in first-quarter
2008 from 219 MMcfd in 2000. The study expects the shale to produce 6-7 bcfd
in the next 5 years.
Some of the newer techniques in the play noted in the study are:
Longer horizontal laterals, up to 3,500 ft, often drilled from pads with
multiple wells, especially in the urban areas. Testing of tighter well
density with laterals, spaced 250-ft apart (25-30) compared with 500 ft between
laterals (50-acre spacing). Simultaneous fracing of wells to increase
recovery.
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Deep Bossier East Texas six
fields 4 counties 65 MMcfd
Wells in Deep Bossier of East Texas reach a 15,000-20,000 ft depth, have
pressures of about 15,000 psi, and have tested at 65 MMcfd. The study notes
that these wells are expensive, costing $10-20/million for a vertical well.
Currently the play has six main fields in four counties: Robertson, Leon,
Freestone, and Limestone.
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Fayetteville shale Arkansas: 877 wells, July, 2008 740 MMcfd
- 90 MMcfd Dec 2006 expects 3.15 bcfd by 2018.
The Fayetteville shale in Arkansas is the shallower and thinner
equivalent of the Barnett shale. The core of the play is in five counties
in central Arkansas: Cleburne, Van Buren, Conway, Faulkner, and White. The
study says as of May 31, 2008, the play had 877 producing wells, with production
in July of 740 MMcfd compared to only 90 MMcfd in December 2006. The study
expects the play to produce 3.15 bcfd by 2018.
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Fayetteville Shale BP Acquires 25% Interest In Chesapeake’s Assets
Pipeline and Gas Journal, Oct 2008
Chesapeake Energy Corporation and BP America have signed a Letter of Intent
for a joint venture whereby BP will acquire a 25% interest in Chesapeake’s
Fayetteville Shale assets in Arkansas for $1.9 billion.
The assets have daily net production of 180 MMcf/d of natural gas and include
540,000 net acres of leasehold that the companies believe could support the
drilling of up to 6,700 future horizontal wells. BP will own 135,000 net acres
of this leasehold and Chesapeake 405,000 net acres.
BP will pay $1.1 billion in cash at closing and $800 million in the remainder
of 2008 and in 2009 by funding 100% of Chesapeake’s 75% share of drilling
and completion expenditures until the $800 million obligation has been funded. |
Haynesville northwestern Louisiana and East Texas: 5-20 MMcfd,
The Haynesville shale is in northwestern Louisiana and East
Texas. Wells in the play initially have produced 5-20 MMcfd, the study said.
The study expects wells to have ultimate gas recovers of 4-8 bcf. Currently,
companies have drilled about 20-25 horizontal wells in the play, and the study
expects about 60-80 rigs could be active in the play by yearend 2008, with
most of the drilling in Caddo and DeSoto Parishes in Louisiana.
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Oklahoma Woodford Arkoma basin of SE 80-acre well 4 bcf of gas.
The Devonian-aged Woodford shale lies at 6,000-14,000 ft depths
in the Arkoma basin of southeast Oklahoma. The study notes that the $6 million
well cost in the Woodford is more than the $2-3/million/well cost in the Fayetteville
and Barnett shales. The study estimates that an 80-acre well in the
Woodford will recover about 4 bcf of gas.
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Atlas Energy Michigan
Antrim Shale: 60 Mmcfe/d
Atlas Energy Michigan, owns interests in approximately 2,400
natural gas wells producing from the Antrim Shale, located in northern Michigan.
The Antrim Shale is a mature play characterized by long-lived reserves and
predictable production rates and as of June 2008 has 613 Bcfe (billion cubic
feet of natural gas equivalents) of proved reserves on DGO’s approximately
273,900 net developed acres and 39,300 net undeveloped acres. Daily production
in the Antrim Shale on the date of the transaction was approximately 60 Mmcfe/d
(million cubic feet equivalent per day).
Atlas Energy Michigan is the largest operator in Michigan’s Antrim Shale,
a biogenic shale found between 500 and 1,500 feet in northern Michigan. Our
reserves in this basin are long-lived and have historically stable production
rates. One of the first shale plays to evolve and mature, Antrim has been
producing since the 1940’s. Although mature, the field continues to expand
through development of technology and successful testing of new areas. The
natural gas in Antrim exists as adsorbed gas on the surface of the shale and
within its natural fractures. The use of horizontal wells has opened up new
areas of development resulting in approximately 2,400 producing wells, with
more than 750 future drilling locations identified. Our technical team in
Michigan has a long operating track record in the Antrim Shale which we believe
has resulted in our strong operating discipline and our position as one of
the lowest-cost producers in the region. We also believe that we have the
most experienced management, technical and operating teams with biogenic
shale formations in the country.
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Atlas Energy Chattanooga
Shale: 4 wells 1/3-1/2mcfgpd
Since the beginning of 2007, Atlas Energy has accumulated
105,000 net acres located in eastern Tennessee. We believe this acreage contains
up to 500 potential horizontal drilling locations in the Chattanooga Shale.
Today, Atlas Energy operates more than 375 vertical wells producing from conventional
zones, as well as the Chattanooga Shale, and is the largest producer of oil
and gas in Tennessee.
The Devonian Chattanooga Shale is an organic, hydrocarbon rich shale found
throughout eastern Tennessee. This productive horizon is located beneath the
Mississippian Fort Payne Limestone at a depth of between 3,000 and 4,000 feet.
The shale thickness ranges from 80 to more than 200 feet and is thought to
be the source rock for the hydrocarbons produced from many of the conventional
reservoirs in Tennessee.
Atlas Energy Tennessee, a subsidiary of Atlas Energy, has drilled or participated
in four successful horizontal wells in the Chattanooga Shale of eastern Tennessee.
Results have indicated that horizontal Chattanooga Shale wells, with a 3,000
foot lateral, are capable of stabilized production into a pipeline of between
300 and 500 Mcfe per day.
Atlas Energy’s affiliate, Atlas Pipeline Partners, is installing two natural
gas processing plants that will be capable of serving a broad area of eastern
Tennessee. Atlas Pipeline’s ownership of these facilities, along with the
recently acquired intrastate pipeline system, offers Atlas Energy an advantage
in acquiring additional leasehold acreage.
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