Operators in the Fayetteville Shale in Arkansas and the Woodford and Caney shales in Oklahoma staked their claims in the gas-rich formations, drilled to hold their land positions, and embarked on a quest to combine the most efficient drilling and completion technologies to leverage their assets.
A rig working the Woodford Shale for Newfield Exploration turns to the right and night as the operator works its substantial position in the gas play. (Photo courtesy of Newfield Exploration)
Just as Mitchell Energy and later Devon Energy completed the early, expensive part of the learning curve in the Barnett Shale in northern Texas and maintained a dominant position, Southwestern Energy led the Fayetteville play and Newfield Exploration Co. stepped in as the landmark company in the Woodford Shale on the Oklahoma side of the basin.
Service companies and dozens of additional operators arrived with their own plans to make the shales work profitably. Together, they converted the Arkoma play into the second most successful shale development, after the Barnett, in the world.
Each operator has an individual approach that works for that company. As a group, they put together nearly every technique that converts an untried gas play into a successful development.
The following is a list of companies operating in the Arkoma shale plays – Caney, Fayetteville, and Woodford:
Antero Resources Corp.
Antero Resources Corp., backed by executives with extensive and successful backgrounds in shales and horizontal drilling, lists more than 100,000 acres of properties with Woodford Shale potential in Oklahoma among its growth prospects.
According to the company’s Web site, it started producing from the Woodford in June 2006 and increased that production to 85 MMcfe/d gross (72 MMcfge/d net).
It currently keeps one drilling rig busy in the play, and it has drilled and completed more than 100 horizontal wells in the basin.
When the company secured US $1 billion in financing through Warburg Pincus in 2007, it was operating 11 drilling rigs and produced 34 MMcf/d of gas from its Woodford properties. It also put together more than 40 miles of gathering lines with some 100 MMcf/d of line capacity.
Antero holds another 26,000 net acres with Woodford Shale potential in the Ardmore Basin of Southern Oklahoma and completed its first horizontal well in that play.
Between the time the company formed in 2002 and the end of 2005,Antero assembled more than 70,000 net acres of leases in the Barnett Shale in the Fort Worth Basin. By the time it sold those properties to XTO Energy in 2005, it was the top vertical well operator in the basin with production rates more than 10%higher than the next best operator. It maintains an affiliation with XTO.
Between February 2003 and its sale to XTO, Antero increased production from 17MMcfge/d to 150MMcfge/d from 250 wells. At one point, it was the second-largest producer in the Barnett and the second most active driller with up to 12 rigs working at the peak. By the sale date it had drilled more than 80 horizontal Barnett wells with laterals up to 4,200 ft long. It also was an early user of multistage fracture techniques and microseismic fracture mapping.
To help move the gas, Antero acquired and built more than 100miles of gathering lines, 21,800 hp of compression capacity, 217MMcf/d of gas dehydration capacity, and 125MMcf/d of carbon dioxide treating capacity.
In addition to its Arkoma Basin properties, Antero holds properties in the Piceance Basin of Colorado and holds 117,000 acres in the Marcellus play in West Virginia and Pennsylvania through an arrangement with Dominion Resources, one of the largest operators in the Appalachian Basin.
Antero originally signed on for 205,000 acres of Dominion property for $552,000, but, as hydrocarbon prices dropped, the companies cut back giving Antero drilling rights on 114,259Marcellus acres for $347 million, or about $3,037 an acre.
Antero’s current production is around 138 MMcfg/d gross, 115 MMcfg/d net.
David H. Arrington Oil & Gas Inc.
David H. Arrington Oil & Gas Inc. has built a reputation as a wildcatter and a gas finder with substantial interests and experience in both the Barnett Shale of North Texas and the Fayetteville Shale in Arkansas.
The company’s 1-14H Beverly Crofford horizontal test in Conway County, Ark., was a new field discovery. The company drilled the well to about 8,000 vertical ft and kicked off horizontally to a measured depth of 11,565 ft in the Fayetteville in Section 14-7n-15w nearly 61?2 miles north of Menifee, Ark. It perforated the well from 8,060 ft to 11,210 ft but didn’t report initial potential.
It followed up with the successful 2-14H Beverly Crofford development well completed two months later in the same section. Again, it didn’t report initial production potential.
Also in Conway County, Arrington permitted the 1-3H Norman new field wildcat in Section 3-7n-16w. That well was projected to a vertical depth of 6,500 ft and a measured depth of 10,000 ft.
It also permitted the 1-20H Embry horizontal new field wildcat in Section 20-7n-17w, also aimed at the Fayetteville Shale. That well was scheduled to reach a total depth at 12,000 ft after drilling vertically to 8,500 ft.
Moving to Independence County, Ark., Arrington drilled the 1-28H Pulliam shallow new field discovery in the Fayetteville. That well, in Section 28-11n-6w reached total depth on a horizontal lateral at 6,000 ft and produced from perforations along the horizontal leg from 2,120 ft to 5,912 ft.
It also drilled the 2-28 Pulliam in the same section. It was holding reports on that well for additional data.
The company also completed the 1-23 Helena Port in Section 23-3s-4e in Phillips County, Ark. In 2006 in the Fayetteville, but it has not yet reported results on that well, according to IHS Inc.
Aurora Oil & Gas Corp.
Aurora Oil & Gas Corp., a prominent independent in the Antrim Shale play in Michigan and the New Albany Shale play in Illinois, holds a small overriding royalty interest in the Woodford Shale in Oklahoma.
Through early 2008, the company held 36,802 gross 32,753 net, acres with Woodford Shale potential but didn’t get around to active operations.
In May 2008, Aurora entered a purchase and sale agreement to sell its properties to Presidium Energy LC for a promissory note with a 9% annual interest rate for US $12 million. According to Aurora, the value of the deal was more than $15 million. That sale was part of an arrangement with interests of other interest owners in approximately 67,000 gross Woodford Shale acres called the Oak Tree Project. Aurora retained a 3% overriding royalty interest in the project, which now covers 71,000 acres. The companies completed the sale on Sept. 15, 2008. Since that time, Presidium completed five initial vertical test wells in the project area.
Presidium was founded by John V. Miller, formerly vice president of Aurora from May 18, 1997, until Feb. 29, 2008.
According to William W. Deneau, chief executive officer, “Completing this transaction creates a winning solution for all parties involved. It generates greater proceeds for the property than were originally anticipated and extinguishes the litigation associated with our joint venture partner in that project area. This is an ideal resolution to a risky and unproductive asset in our portfolio. Going forward, our 3% overriding royalty interest will allow us to participate in what could be a tremendous upside while eliminating downside risk to our enterprise.”
BP North America Gas
BP North America Gas moved into the great US shale stampede late in the game, but when it moved, it moved decisively and took advantage of some of the top expertise in the field.
It moved into the Arkoma Basin with major purchases in the Woodford Shale in eastern Oklahoma and the Fayetteville Shale in north central Arkansas from Chesapeake Energy.
According to an article in the company’s Horizon magazine, “Executives in BP North America Gas (NA Gas) have acted quickly and decisively to gain a quality stake in US natural shale gas plays; starting with the US $1.75 billion acquisition of the Woodford shale play.
“Purchased from Chesapeake Energy, it is located in the Arkoma Basin of Oklahoma and covers 37,000 hectares (90,000 acres).”
That purchase took all of Chesapeake’s properties in the Woodford in the Arkoma Basin.
Those properties lie in Atoka, Coal, Hughes, and Pittsburg counties and, at the time of the sale announcement in July 2008, produced some 50 MMcfge/d.
With the sale announcement, Andy Inglis, BP chief executive of exploration and production, said, “This acquisition has the potential to more than double our existing production of over 200 million standard cubic ft per day from our Arkoma operations.”
Andy Hopwood, vice president, BP America Inc., added, “This is an important move for NA Gas. As natural gas prices continue to rise in North America, BP has determined that investment in shale gas development aligns with our plans for growth.
“Shale gas is going to become an important component of natural gas supply in North America during the next decades. We want to be part of this trend and continue to develop in other locations,” he said.
Two months later, the two companies announced another major agreement involving Chesapeake’s Fayetteville properties.
In that deal, BP signed a letter of intent to buy a 25% interest in all of Chesapeake’s Fayetteville shale properties in Arkansas for $1.9 billion.
The full Chesapeake package consisted of 540,000 net acres of leases and 180 MMcfge/d of gas production. Those properties could support as many as 6,700 horizontal wells. Following the transaction, BP controlled a net 135,000 acres and 45MMcfge/d of gas production and Chesapeake retained 405,000 net acres.
It wasn’t pure cash deal, but it was similar to an earlier arrangement Chesapeake had made with Plains Exploration and Production (PXP) on Chesapeake’s Haynesville properties.
Under the new arrangement, BP agreed to pay $1.1 billion in cash and would contribute another $800 million in 2008 and 2009 by funding Chesapeake’s 75% share of drilling and completion expenses in the Fayetteville. That contribution would earn BP the right to a 25% participation in additional leases.
“This transaction, when combined with our recent Woodford acquisition, establishes a material position in the two attractive shale plays in the Arkoma Basin. Together with our substantial position in the emerging Haynesville Shale play in east Texas, BP has made a strategic entry into three top tier shale plays in North America and established potential shale resources of 1 billion bbl oil equivalent net to BP. Development of these resources, along with our leading position in coalbed-methane production, and our extensive tight gas plays throughout North America, will enhance BP’s position as a leader in unconventional gas technology and enable growth of our North American onshore natural gas production from today’s level of 470,000 boe. We look forward to working closely with Chesapeake as they develop the significant Fayetteville play,” Inglis said.
It was a great deal for Chesapeake, as well. “The PXP Haynesville Shale joint venture and the BP Fayetteville Shale joint venture together will pay for approximately $2.5 billion of Chesapeake’s drilling and completion expenditures currently planned for the second half of 2008 through 2010,” said Chesapeake Chief Executive Officer Aubrey McClendon.
According to the Horizon magazine article following the Woodford purchase, 70% of BP North America’s 470,000 boe/d of gas production came from unconventional resources. Most of that came from tight sands and coalbed methane.
BP began examining shale gas potential as operators clamored to develop the Barnett Shale in north Texas and as shale plays began developing in other states. It put a multidisciplinary team to work on the economics of appraising and developing the gas and the application of existing technologies, mainly horizontal drilling and fracture techniques.
That team ranked the plays, looked for opportunities and made its purchase decisions backed by hard economics.
“If we didn’t go forward and brave the new challenges of shale gas, BP would be missing out on a major new direction for gas supplies that will highlight the next two decades,” Hopwood said.
In a presentation, BP said its position in the Haynesville, Woodford, and Fayetteville shales combined represent some 1 billion boe of resources that could produce up to100,000 boe/d by 2015.
Carrizo Oil & Gas Inc.
Carrizo Oil & Gas Inc. chose a variety of interests in the oilpatch, but it clearly likes gas shales. It picked its shales, gathered land, built expertise in the plays and went to work.
It controls 75,000 net acres in the Barnett in the Fort Worth Basin, 95,000 net acres in the Marcellus in the Appalachian Basin, 57,000 net acres in the Barnett and Woodford in the Marfa Basin of west Texas, 137,000 net acres in the Black Warrior Basin of Alabama, 24,000 net acres in the Fayetteville in Arkansas, and 22,000 net acres in the New Albany Shale in the Illinois Basin.
Clearly, Carrizo’s concentration among the shales lies in its activity in the Barnett, followed by the Marcellus. At this point the other shales are in the also-ran category.
It has five rigs working the Barnett, four in the core area. With those rigs it planned to raise production to 100MMcf/d by the end of March 2009 and 125 MMcf/d by the end of the year. It still has more than 650 Barnett locations left to drill on 60-acres spacing, and its wells could reach 1 Tcf in producible resources, Carrizo officers said in a January 2009 presentation at Pritchard Capital Partners Energy 2009 Conference.
It planned to spend US $235 million on operations in the Barnett in 2008 and $3 million in the other shales combined. For 2009, poorer economics persuaded the company to cut Barnett spending to $150 million and other shales to nothing.
It had participated in 15 Fayetteville wells through 2007 and planned to join in several more non-operated wells to that formation in 2008.
Funds earmarked for acquisitions dropped from $169 million in the Barnett in 2008 to $15 million in 2009. Marcellus acquisition fell from $65 million to nothing, and purchases in other shales fell from $21 million to $2 million. Outside of the Barnett, Carrizo drilled two Marcellus wells and awaited completions at the end of 2008. It permitted five more Marcellus wells.
Chesapeake Energy Corp.
A lot of companies make money by getting into gas shales. Chesapeake Energy Corp. put a twist on that philosophy by making money selling whole and partial interests in its shale holdings.
The philosophy worked well in the Arkoma Basin as it sold all of its holdings in the Woodford play in eastern
A lot of companies make money by getting into gas shales. Chesapeake Energy Corp. put a twist on that philosophy by making money selling whole and partial interests in its shale holdings.
Oklahoma and 25% of its holdings in the Fayetteville play in north central Arkansas. Both parcels went to BP in deals with a total value of some US $3.65 billion.
Chesapeake sold approximately 90,000 acres of properties with Caney and Woodford potential in Oklahoma. Those properties are in Atoka, Coal, Hughes, and Pittsburg counties and, at the time of the sale announcement in July 2008, produced some 50 MMcfge/d.
It sold a 25% interest in its Fayetteville Shale properties in Arkansas for $1.9 billion; $1.1 billion of that was in cash and the remainder is being paid in the form of drilling and completion carries on the joint venture properties in 2008 and 2009.
Following the transaction, BP held 135,000 net acres of land and 45 MMcfge/d of production. By the end of 2008, after the sale, Chesapeake still was the second-largest leaseholder in the Fayetteville with 415,000 net acres of land with an implied value – based on the BP sale – of $6 billion.
For its own purposes, Chesapeake set an implied value of $12,500 an acre, or $5.2 billion for the properties.
For 2009, Chesapeake set a $550-million budget for the Fayetteville but it will put up only $50 million of that amount. BP will carry the rest.
It planned to operate an average 20 drilling rigs in the play during the year to add 325 Bcfe of new reserves at a finding cost of 15 cents/Mcfe for the company.
Figuring 80-acre spacing for the Fayetteville properties, Chesapeake had sites for a net 3,700 undrilled wells and an estimated 2.2 Bcfe per well in recoverable hydrocarbons.
Throughout the play, it held 535 Bcfe in net proved reserves, 6.6 Tcfe in risked unproved reserves, and 8.9 Tcfe in unrisked unproved reserves.
The company’s Fayetteville net production reached 145 MMcfe/d by the end of September 2008.
Following the Fayetteville deal, Andy Inglis, BP chief executive of exploration and production said, “This transaction, when combined with our recent Woodford acquisition, establishes a material position in the two attractive shale plays in the Arkoma Basin. Together with our substantial position in the emerging Haynesville Shale play in east Texas, BP has made a strategic entry into three top tier shale plays in North America and established potential shale resources of 1 billion boe net to BP.”
A mid-2008 report by IHS Inc. said Chesapeake was producing 100MMcfge/d of gas from the Fayetteville and production had climbed 900% over the past year. At that time, the company was drilling horizontal wells at a cost of $3million and it had drilled some 140 horizontal wells since it entered the play in 2007.
Chesapeake backed its enthusiasm about its Fayetteville holdings in October 2008 when its Chesapeake Energy Marketing Inc. subsidiary signed a 10-year agreement for firm transportation of 375 MMcfg/d of gas with an option to add another 125 MMcfg/d on the new Fayetteville Express Pipeline being built by Kinder Morgan Energy Partners LP and Energy Transfer Partners LP.
“We are pleased to announce that we have secured substantial new takeaway capacity for our Fayetteville Shale production that will provide Chesapeake and our 25% partner, BP America, with improved access to more favorable natural gas markets at an attractive transportation rate. This agreement helps to reduce both basis risk and pricing volatility and will accommodate the substantial growth we anticipate from the Fayetteville Shale play in the years ahead,” said Aubrey K. McClendon, chief executive officer of Chesapeake.
A May 2008 IHS report showed the kinds of production Chesapeake got from its Fayetteville wells. Its 3-17HMartindill 8-7 in White County, Ark., flowed 3.33 MMcf/d of gas through perforations between 4,985 ft and 10,112 ft from a northwest lateral.
In the same quarter-section, the 1-17H Martin dill tested 1.97 MMcfg/d from a lateral perforated from 5,053 ft to 8,422 ft after an acid treatment and a five-stage fracture treatment. Between October 2006 and February 2008, the well produced 563MMcf of gas and averaged 669Mcf/d of gas in February.
McClendon told analysts in an August 2008 presentation recorded by Seeking Alpha, “In the Fayetteville, we are drilling our best wells ever, due to improvements and where we position our laterals within the Fayetteville; longer lateral lengths, better completion techniques, and the arrival of certain new 3-D information that help us avoid geological pitfalls.”
Answering a question from an analyst, McClendon showed insight for his attitude for the Fayetteville and possibly for BP’s entry into the play. He said, “…if you’re worried about a gas surplus in America, if you recognize that the Gulf of Mexico is going nowhere, if you recognize that Canada is really going nowhere, if you recognize that the Rockies are bottlenecked again for the next couple of years, you really only have to solve for the Barnett and they Haynesville, and if you listen to what EOG said this week and believe what we said today, and if you believe what I said about the Haynesville, that it won’t be able to exceed pipeline constraints, then there are really only two other shale plays out there that you really need to bother with, and that would be the Fayetteville and the Woodford. And we think those increases a year are 200, 300, 400 million a day (for each play) and certainly not market movers. And finally, the play that people have expressed concern about would be the Marcellus, and it’s not going to be anything significant for probably another five years or so.”
In time, he added, the Fayetteville will be bigger than the Woodford because it covers more territory.
Continental Resources Inc.
The Arkoma Basin Woodford play may not be Continental Resources’ biggest but it looks like one of the best for the company.
Continental holds 47,000 acres in the Woodford, compared with more than 12 times that acreage (581,000 acres) in the Bakken Shale play in Montana and North Dakota where it holds the title of largest leaseholder. It considers both areas impact plays for the company, according to a corporate presentation.
At the end of the fourth quarter of 2008, it figured 3 Bcf/well in gross reserves for a Woodford well, assuming eight wells per section.
In the fourth quarter of 2008, it produced 3,276 boe/d from the Woodford, up from1,338 boe/d in the same quarter a year earlier. By year-end 2008, it posted 30.7 million boe in proved reserves in the Woodford, up from 8.9 million boe at the same time the previous year.
To reach that level, the company drilled 41 gross, 9 net, wells during the fourth quarter. Those wells added 25% to its Woodford production in the fourth quarter of 2008, compared with the end of the previous quarter. It dropped its rig count from six rigs in the third quarter to one rig in the fourth quarter.
Its best well in the play at that point was the Blevins 1-1H in Hughes County, Okla. That well, with Continental holding a 41% working interest, average 8.1MMcf/d of gas during a seven-day production test. It later raised the seven day average rate to 10.4 MMcf/d. That well was east of the company’s Salt Creek exploratory area.
The company found good results from simul-frac treat- ments on its Woodford wells. It completed the six-well Luna-Pratt simul-frac project in the third quarter of 2008 by stimulating the horizontal laterals of the six wells, one pair at a time. The wells averaged 3.8 MMcf/d gross each in seven-day production tests, with little variation among the wells.
It started drilling the simul-frac wells in March 2008 and finished that four-well job in late April with flow rates averaging 3.8 MMcf/d of gas per well, or 40% more than original wells in the spacing units. Following up on the simul-frac technology, Continental used the treatment in seven wells in its Pasquali area. The wells flowed at an average rate of 2.44 MMcf/d of gas with the best well flowing at nearly 3.6MMcf/d of gas. The two simul-frac wells in the Wilson project flowed at 8.57MMcf/d and 5.98MMcf/d of gas, respectively.
Although Continental had planned to spend US $99 million on the Woodford in 2009, the company cut that figure to $56 million for drilling-related activity plus $7 million for land and seismic acquisition in its revised capital expenditure budget, which was announced Feb. 26, 2009. That still will allow the company to participate in 63 gross, eight net, wells in 2009.
The company considers its Ashland area a development area for the Woodford, while the Salt Creek and East McAlester areas are exploratory projects. During 2008, it acquired 25 sq miles of 3-D seismic over Salt Creek and 55 sq miles of 3-D seismic over East McAlester to optimize well planning and production.
Devon Energy Corp.
Devon Energy Corp. engraved its name on the gas shale landmark when it took over Mitchell Energy & Development Corp.’s Barnett Shale operations in north Texas and pioneered rapid development, advanced technology, and a land rush for gas shale formations across the country. Eastern Oklahoma’s Woodford shale is part of the land rush, and Devon is a big name in that play.
Devon set a number of records as its Barnett operations made it the biggest gas producer in Texas and helped make it the third-biggest gas producer in the nation. It drilled the first Barnett horizontal well and the first horizontal well on 1,000-ft spacing. It also was the first company to reach 1.0 Bcfge/d of net production and has since added another 150 Bcfge/d. It also was the first company to reach 1 Tcf of gross cumulative gas production.
The Barnett and Woodford have some similarities, according to Devon figures, The Barnett lies at about 7,500 ft and the Woodford lies at 7,550 ft. Both formations offer 6% porosity. At about 389 net ft, the Barnett is more than twice as thick as the Woodford’s 175 ft. That is reflected in the gas in place. The Barnett offers 147 Bcf/sq mile compared with 60 Bcf/sq mile for the Woodford.
The company has more than 3,800 Barnett producing wells on 801,000 gross acres in the Barnett and in 2008, the company drilled 659 wells (559 operated) in the play.
Devon set a number of records as its Barnett operations made it the biggest gas producer in Texas and helped make it the third-biggest gas producer in the nation. (Photo courtesy of Devon Energy Corp.)
Devon drilled its first Woodford well in 2004 and its first horizontal well in the play in 2005. Still, the Woodford trailed Barnett operations significantly with an average of 64 MMcfeg/d of net production in the fourth quarter of 2008, according to Steve Hadden, executive vice president of exploration and production, at the company’s fourth quarter conference call, recorded by Thomson Financial.
That figure was up 35%fromthe third-quarter average and 165% compared with the fourth quarter of 2007.
In 2008, the company drilled 132 horizontal (48 operated) wells with an average per-well initial production rate of 4.4 MMcfg/d.At that time, it had six rigs working the play and planned to run 3 rigs and drill 26 operated wells in 2009.
To support its Woodford operations, Devon completed the US $30-million Northridge gas processing plant with a capacity to process up to 200 MMcf/d of liquids-rich gas. That plant started operations in early October 2008. Devon has purchased or acquired 310 sq miles of 3-D seismic to de-risk the play. At year end, Devon had 100,000 gross acres of Woodford properties in Pittsburg, Hughes, Coal, and Atoka counties in Oklahoma.
Edge Petroleum Corp.
Edge Petroleum Corp. set its sights on Fayetteville/Moorefield shale production on the Arkansas side of the Arkoma Basin and it’s pushing forward carefully to raise its production.
The company entered the Arkansas Shale play in 2005 with the acquisition of 5,661 gross, 4,692 net, acres in the heart of the eastern core. The properties were prime territory with nearby properties held by Chesapeake and Southwestern Energy and on strike with wells completed by Chesapeake at initial rates of 3 MMcfge/d to 5 MMcfge/d. The Fayetteville/Moorefield is more than 500 gross ft thick in the area in southern Cleburne County.
Edge’s initial well tested between 1.1MMcfge/d and 1.3 MMcfge/d as it recovered frac fluids, but the frac treatment broke through to water below the formation.
By the end of the following year, Edge had one company- operated well and participation in one outside-operated well. Those totals rose to five operated wells and two outside- operated wells to give the company a total nine gross wells by the end of 2007. At that time, Edge had potential for 246 wells on proved, probable, possible, and exploratory locations.
John W. Elias, chairman, president, and chief operating officer, said, “We ended 2007 with production and proved reserves lower than we expected, due primarily to the drilling of fewer wells than we had planned, a dry hole at a proved undeveloped location on the acquired properties in southeast Texas and a disappointing start to our Arkansas Shale program where fracture stimulation during the completion of our initial wells caused communication with an underlying water-bearing zone. Many of the planned 2007 wells have been deferred and some of the reserves we had originally expected to be classified as proved have been moved to a non-proved category, pushing many of these growth opportunities out into the future. We still believe there may be significant resource potential associated with our Arkansas acreage.”
By February 2008, Edge had 100Mcfge/d of production from 500 MMcfge of Fayetteville/Moorefield proved reserves. It had 100.8 Bcfge of resource potential in the shales.
By the end of the third quarter of 2008, Edge said it planned to participate with its partners in at least two wells early in 2009 in locations near wells recently completed at rates of more than 2 MMcfge/d.
The company also applied for a permit to re-inject produced water into an existing well. When it gets that permit the company can bring three shut-in wells back on line. Edge has working interests from 80% to 100% in those wells.
Hallwood Energy LP
The Hallwood Energy LP, a subsidiary of The Hallwood Group Inc., with some 400,000 acres of Fayetteville leases is one of the most active operators in the play and one of the most active wildcatters.
Hallwood Energy’s position in the Fayetteville and its south Louisiana and west Texas properties prompted Canada’s Talisman Energy Inc. to take a one-third farmout in some 350,000 gross acres of Hallwood properties through its FEI Shale Inc. (Fortuna Energy) subsidiary. Fortuna also works Talisman’s Trenton-Black River play in New York and is expanding those activities into Marcellus Shale exploitation in New York and Pennsylvania.
Under that arrangement, Talisman will make a series of payments to Hallwood over a period of up to 18 months. Through June 30, 2008, Talisman had paid US $35 million, primarily in drilling costs, to earn interests in the properties. Hallwood is the operator. Effectively, Talisman agreed to a payment of $60 million to cover 10% of Hallwood’s interests. Talisman had the option of paying the remaining $$65 million, for a total $125 million for the full one-third interest.
That may change. Talisman also hired Hallwood to provide the Canadian company with consulting services for a year.
On the wildcat side of the ledger, Hallwood has abandoned wildcat locations scheduled to the Fayetteville in Faulkner, Monroe, Prairie, White, and Woodruff counties on Arkansas as it tried to extend the economic pay area.
At the same time, the company has chalked up successes, according to IHS Energy reports.
Its 2-5H Kerr in White County was an extension discovery. The company completed that well with 24 sets of perforations in a gross horizontal Fayetteville section between 6,760 ft and 8,952 ft after reaching a measured depth of 9,100 ft. True vertical depth was 6,900 ft. It followed up with a six-stage slickwater frac treatment. The well tested for an initial potential of 518 Mcf/d of gas.
The 1-15H Conder horizontal test, also in White County, resulted in a new field wildcat discovery. Hallwood drilled that well to a vertical depth of 7,500 ft and finished with a lateral leg that reached 8,402 ft in the Fayetteville.
It perforated in 12 sections between 7,050 ft and 8,333 ft then performed a four-stage fracture treatment. The company didn’t report initial production figures.
Still in White County, it completed another new field discovery in the Fayetteville with its 1-22HCrutchfield.That well reached a true vertical depth of 7,900 ft before turning to a lateral leg that reached total depth at 10,000 ft.
It perforated in four segments between 8,192 ft and 8,472 ft in the horizontal leg of the well and finished the job with one fracture treatment with 1,237 barrels of water, 148,520 lb of 40/70 sand, 3.785Mcf of foam with a slickwater additive, and nitrogen gas. The well tested at 576 Mcf/d of gas through a 16?16-in. choke.
Hallwood Petroleum Inc.’s 1-32 Harlan resulted in another new field discovery in White County. That 2007 Fayetteville well drilled vertically to 9,000 ft and tested for 785Mcfg/d from the Fayetteville Shale. Completion details included perforations in three zones from 8,010 ft to 8,381 ft and a single frac treatment with 1.8 million bbl of water, 346,640 lb of sand in a slickwater job.
Hallwood’s 4-34H new field wildcat resulted in a field discovery, also inWhite County. The first leg of the dual-lateral well drilled vertically to 7,850 ft and reached total depth in the lateral at 9,900 ft. The second leg reached a vertical depth of 8,113 ft and reached laterally to 9,580 ft. It perforated in nine segments in the first lateral, conducted an acid treatment and finished with a three-stage frac to test for 615 Mcf/d of gas. Moving to Woodruff County, Hallwood drilled the 1-8 Conner Farms vertically to 5,728 ft. That new field wildcat discovery took perforations in two sections and a single frac treatment. The company didn’t report a production rate.
Hallwood didn’t limit its activities to drilling. In July 2008, first gas flowed through its Antioch Gathering System and the company flowed 6 MMcf/d of gas into the Mississippi River Transportation Co. pipeline. The $5 million gathering system included 15 miles of line in White County. At that time, Hallwood said only one well was hooked into the gathering system. It planned to add more wells with the help of its three active drilling rigs working the Fayetteville Shale.
Kerogen Resources Inc.
Kerogen Resources Inc. specializes in identifying unconventional oil and gas shale opportunities that other companies have overlooked, and then applies geoscience and reservoir and production engineering to bring out the potential.
With initial financing and US $20 million in debt, it concentrated its efforts on the Barnett gas shale, the Bakken oil shale and underlying Three Forks sand in the Williston Basin, and the Montney shale-siltstone-tight sand in British Columbia. In 2008, it raised its net production from less than 200 boe/d to more than 1,400 boe/d with a bright outlook for 2009 and a change in philosophy from a prospect-generation company to an exploration and production company.
Along the way, Kerogen formed a joint venture with Triangle Petroleum Corp. to explore 34,000 gross, 20,000 net acres in the Fayetteville play in Conway, Faulkner, and Pope counties in Arkansas. It added Van Buren County as part of a 52-township area of mutual interest and the companies agreed to drill a horizontal well to the popular shale.
By early 2008, however, Triangle said it planned to sell its Fayetteville properties calling the leases unproven and non-productive.
Both companies showed up at the North American Prospect Expo in early 2009 with Fayetteville leases on their sales list.
Lario Oil & Gas Co.
Lario’s founder started work in the oilpatch in 1916, but the company’s approach to exploration and production is anything but old fashioned. Among its working plays in the US and Canada are the Woodford and Fayetteville shales in the Arkoma Basin, the Bakken Shale, the Barnett Shale, and the Mississippian Chert.
That translates to low-risk drilling with big upside potential in areas where the learning curve can increase production and lower drilling costs.
Lario entered the Woodford Shale play in 2007 with 1,508 net, 12,778 gross, acres of leases. Drilling on the leases started in the fall of 2008, and the company now has small working interests in more than 30 producing wells with another 12 wells permitted.
Based on 160-acre spacing the company has more than 288 proved, possible, and probable drilling locations.
That doesn’t mean Lario is a big player. It holds working interests averaging 3.3% on those drilling locations, and it calculates proved, probable, and possible reserves of 23 Bcf net to Lario.
The company also entered a development contract on the 14,000 net acres it holds in the Fayetteville Shale in Arkansas where a 3-D seismic program was initiated. Impressive production rates on the Woodford and Bakken wells persuaded the company to spend 65% of its capital expenditures in those areas in 2008.
Metro Energy Group Inc.
Metro Energy Group was among the first operators in the Woodford Shale in Oklahoma and it works closely with large operators such as Devon Energy and Newfield.
Through its joint venture company it has drilled 28 vertical wells to identify fracture techniques, and it operates 18 wells.
Among Woodford Shale wells, IHS Inc. identified five development wells operated by Metro Energy.
The 7-19 Snell Heirs in Gregory Field was scheduled to Wilcox at 4,200 ft in May of 2006. It reached to top of the Woodford at 3,663 ft. The company perforated the Woodford between 3,670 ft and 3,695 ft, acidized the well, and conducted a slickwater frac job in the vertical well. It tested for 250 Mcf/d of gas.
It drilled the other four Woodford Shale development wells in Weleetka District East Field. All four were scheduled to the Wilcox but completed with fracture treatments in Woodford vertical wells in 2005.
It completed the 4018 Snell Heirs for 180 Mcf/d of gas, the 1-17 Longview for 150 Mcf/d of gas, the 1-17 Snell Heirs for 135Mcf/d of gas, and the 2-17 Longview for 240 Mcf/d of gas.
All the wells were in Okfuskee County, Okla.
Newfield Exploration Co.
Every shale play has a clear number one player. It’s Devon Energy in the Barnett, Southwestern Energy in the Fayetteville, and Newfield Exploration Co. in the Woodford/Caney Shale on the Oklahoma side of the Arkoma Basin.
Gas price and finding cost changes make a big difference in Woodford Shale returns. (Graph courtesy of Newfield Exploration Co.)
At the end of 2008, the company was the most active driller with 165,000 net acres in the play and 85%of that was held by production. That production totaled 265 MMcfge/d, up from 200MMcfge/d at the end of the second quarter, according to a company presentation at the January 2009 Goldman Sachs Global Energy Conference. That acreage covers 2,500 potential drilling locations.
For perspective, at year-end 2008, the industry had 45 rigs working the Woodford play, and Newfield operated 13 of them. Newfield owned 225 operated horizontal wells of the 750 horizontal wells producing for the whole industry.
For Newfield, as with other operators in the basin, the Woodford play includes more than the Woodford. In Newfield’s case, it includes the Caney, Wapanucka, and Cromwell formations, as well. Breaking down the yearend 2007 numbers, Newfield had a remaining unrisked resource of 6 Tcfe in the Woodford, and an unrisked remaining resource of 3.6 Tcf in the other three formations.
Unproved rised reserves totaled 5.3 Tcf from 2,150 potential locations in the Woodford and another 1.8 Tcf from 1,300 locations in the other three zones.
Newfield planned to spend US $2 billion on capital expenditures in 2009, down from $2.2 billion in 2008, but worsening economic conditions persuaded the company to pull back to $1.45 billion in 2009.
During those periods, it increased the percentage of capital spending devoted to the Woodford from 33% in 2008, to an initial 41%for 2009 and a final 45%for 2009. The only other area in the company portfolio with an increased spending percentage was the Gulf of Mexico.
The money dedicated to the Woodford will keep 12 rigs running and should raise production from the shale by 30%.
The company also works an aggressive program to increase production and lower costs. For example, pad drilling lowers finding and development costs, and extended laterals increase estimated ultimate recoveries from each well.
It’s still working on new ideas. Coming up, it will test dual 4,500-foot laterals, it will drill its first Wapanucka formation horizontal well for possible commingling, and it plans to test a “super-extended” lateral of 8,000 ft to 10,000 ft.
Cost control assumes the company has a base line to improve upon. Newfield has a good grip on that baseline.
Assuming average reserves of 4 Bcfge for a horizontal well and an 81% net revenue interest, the company’s production tax for the first 48 months, or until payout, is 1.09%. Thereafter, the production tax rises to 7.09%.Wellhead prices in the Arkoma Basin are about 75 cents/MMBtu lower than the Henry Hub price, and high-quality Woodford gas comes out of the hole at 1,050 Btu/Mcf.
The typical production curve starts with initial output of 4.5 MMcfge/d and drops 62% during the first year to about 1.3 MMcfge/d. It falls another 28% in the second year and declines as a shallower level thereafter, easing to a 7%decline in the eight production year.
With that background, the company offers its well economics assumptions at fixed finding and development costs of $1.75/Mcf and $2/Mcf.
It drills eight wells horizontal per section. Laterals on current wells run around 4,100 ft, and it costs between $5 million and $6 million to drill and complete as Woodford horizontal well.
The economics are straightforward.
Newfield had 600 Bcfge in net proved reserves in the play at the end of 2007, but it estimated future reserves between 5.6 Tcfge and 6.2 Tcfge. It also estimated it would need between $9.6 billion and $10.3 billion to extract those reserves.
Production rates don’t mean much if it can’t reach markets. Newfield signed agreements for 300,000 decatherms per day of gas on the MidContinent Express Pipe-line and may add another 150,000 decatherms per day to that rate. It also has 40,000 decatherms of firm capacity in 2008 on the Laclede EnergyResourcesLine, and that increased to 50,000 decatherms a day in 2009.
Pablo Energy II LLC
Pablo Energy II LLC, a subsidiary of Cactus Feeders, the second- largest cattle feedlot company in the US, is one of the more active operators working the Woodford/Caney gas shale play in Oklahoma’s Arkoma Basin.
According to the “First Crisman Report on Shale Gas in the Arkoma Basin,” by Peter Falko at Texas A&M University, published in August 2008, Pablo ranked sixth among the top 10 operators in the play with 13 producing wells. That placed the company higher on the list than XTO Energy and lower than St. Mary Land & Exploration Co.
During 2008, the company completed 14 wells in Centrahoma, Coalgate, and Olney Northeast fields in Coal County and TAField and an unnamed field in Atoka County, Okla. The wells showed initial potentials ranging from 759 Mcfge/d to 3.7MMcfge/d, according to the Oklahoma Geological Society.
IHS Inc. figures show the company completed its 1H-23 Tomlinson in CoalgateWest Field in Coal County. That well reached the Caney at 5,992 ft and the Woodford Shale at 6,297 ft and traveled laterally to a total depth of 10,888 ft. After an acid wash and fracture treatment the well showed an initial potential of 5.3 MMcfg/d of gas from the Woodford.
The company also staked the 2H-25 Battles in Coalgate Field. That well is projected to a vertical depth of 6,750 ft and a measured depth of 11,750 ft.
Pablo reaches beyond the safe approach of working development wells, too. In early 2008 it completed the southernmost horizontal Woodford wildcat in Atoka County. That well, the 1H-24 Cox, showed an initial potential of 3.28 MMcfg/d of gas through a 64/64-in. choke from perforations in 27 three-ft intervals. It acidized the well and fractured the horizontal section in seven stages. That well was almost six miles south of the nearest producing Woodford horizontal well.
The company also made sure early in 2007 that it got its production to market as it formed the Pablo Gathering subsidiary to partner with Enogex Atoka LLC to form Atoka Midstream LLC, a gas gathering and processing company.
Pathfinder Exploration LLC
Pathfinder Exploration LLC is a veteran operator in the Fayetteville Shale play in the eastern Arkoma Basin.
The company attracted the attention of Shell Exploration & Production Co., and that company entered into a joint venture agreement with Pathfinder in 2006 to look at Fayetteville Shale prospects in several Arkansas counties. At the time, Shell had purchased approximately 70,000 acres of leases in the play from four independent operators.
Under the agreement, Pathfinder is the operator of the joint venture.
Among projects listed by IHS Inc., Pathfinder started drilling the 1-19H Yingling 9-6 in White County to the Fayetteville at 6,345 ft including a vertical depth of 4,550 ft.
The company still hasn’t completed its 1-20H J Smith wildcat, also in White County. It spudded that well in late 2007 and reached total depth at 8,500 ft in February 2008.
The situation was similar for the company’s 1-18H Sullivan 9-6 wildcat. It began drilling and reached total depth at 7,113 ft in January 2008 with a 2,300-ft lateral.
In Woodruff County, Pathfinder drilled the 1-12 Fitzhugh 8-4 wildcat to 6,000 ft in late 2007. In early 2009, that well retained tight-hole status.
Penn Virginia Corp.
The nation’s shale plays rate high with Penn Virginia Corp. and its subsidiaries. The company has substantial interests in the major shale plays in the US, but the Woodford and Fayetteville shales in the Arkoma Basin aren’t near the top of its operating priorities.
A 2009 presentation lists the Woodford as an emerging play with the Marcellus Shale and the Fayetteville ranks above “other plays” with the Lower Huron and Bakken shales, the Cotton Valley and Hartshorne coalbed methane.
The company’s planned to spend US $236 million, or 94% of its 2009 capital budget, on 65 development drilling and related activities. The Haynesville Shale in east Texas will get $87 million of that for 18 gross, 12 net, horizontal wells. Another $50 million will go into 22 gross, 21.4 net, horizontal Selma Chalk wells.
Penn Virginia directed $58 million of those funds into the Mid-Continent region for 12 gross, 6.4 net, horizontal Granite Wash wells and four gross, 0.8 net, non-operated Woodford Shale wells. It set no money aside for exploratory drilling in either the Woodford or the Fayetteville shales.
A third-quarter 2008 status report said the company was involved in three gross, 0.5 net, horizontal Woodford Shale wells and three gross, 0.3 net, non-operated horizontal Fayetteville Shale wells.
The Woodford wells produced at initial rates of 3.5MMcfge, 4.5 MMcfge, and 2.7 MMcfge a day. The company release said, “Based on the encouraging results of the five Woodford Shale wells in which we have participated to date, we plan to continue to participate in the drilling of additional wells in the near term in the Arkoma Basin.
A status report in a January 2008 presentation said the company had participated in 14 gross, 6.4 net, Fayetteville wells and four gross, 1.9 net, Woodford wells.
Penn Virginia controlled approximately 40,000 net acres with an unrisked exploratory potential of some 200 Bcfe in the Woodford/Caney shales in both the Arkoma and Anadarko Basin in early 2008.
Petrohawk Energy Corp.
PetrohawkEnergyCorp. made a name for itself as one of the premier smaller operators in the Haynesville play in east Texas and north Louisiana, and it’s carrying that reputation to its Fayetteville Shale operations in the Arkoma Basin.
The Haynesville remains top priority. Among the 23 drilling rigs the company plans to operate in 2009, 12 will work the Haynesville and two will handle Fayetteville operations. The company also cut its 2009 capital budget from an earlier estimate of US $1.5 billion to a new level of $1 billion. The company spent $395 million on the Fayetteville in 2008 but budgeted only $100 million for 2009, down from an initially planned $175 million before the price downturn.
Still, in reducing the capital budget, Petrohawk said it was directing the bulk of its funds toward the plays with the highest returns, and those plays were the Haynesville and Fayetteville shales.
According to a company release, “The reallocation of capital reflects an increased emphasis on development of nonproved locations in Petrohawk’s successful Haynesville and Fayetteville shale projects, with the benefit of higher expected overall reserve growth potential for the company. Petrohawk’s production guidance for 2009 represents 25%to 35%drillbit growth over 2008 estimated annual production of 305 MMcfge/d.
Future development of the Fayetteville, the company said, will depend on availability of gas processing and gas gathering and pipeline systems.
Petrohawk also has Woodford Shale properties in both the Arkoma and Ardmore basins, but those are not high enough on the priority list that the company talks about them during its presentations. In mid-2008, it held 14,000 net, 15,000 gross, acres in the Caney-Woodford Shale play in the Pine Hollow South region of MacIntosh County, Okla.
Petrohawk’s Fayetteville holdings got a big boost in 2007 when the company bought out Alta Resources LLC, Tepee Petroleum Co., and Contago Oil&Gas Co. holdings for $343 million. That property in Van Buren and Conway counties in Arkansas included some 24,000 net acres of leases in the play about 50% operated.
Currently, Petrohawk holds 157,000 net acres in the play, 155,000 undeveloped, with 100 Bcfe of proved reserves and 3.1 Tcfe of resource potential from 2,500 net drilling locations.
It estimates well costs between $1.75 million and $2.75 million to reach estimated ultimate recoveries between 1 Bcfge and 4 Bcfge per well, according to a January 2009 presentation. It had an aggressive program in the play in 2008. In the third quarter, it was involved in 45 operated and 36 non-operated wells as it working 11 drilling rigs, including one spudder rig. Four of those wells tested for more than
3.9MMcfge/d of initial production and one tested for more than 5 MMcfge/d.
Those higher production rates came from improved completion techniques, including longer laterals and cemented liners with more perforations, Petrohawk said.
For example, it completed one well with a 10-stage cemented liner frac job with a lateral of more than 3,700 ft, and, at the end of the third quarter of 2008, planned a well with a lateral of 5,500 and 15-stage fractured treatment.
Its production from the Fayetteville during the third quarter exceeded 115 MMcfge/d gross, 65 MMcfge/d net, but that included restrictions from construction delays on the Boardwalk pipeline, which went into service on November.
Not all the wells fall under the Petrohawk name. Company president FloydWilson also is president of One TEC, P-H Energy, KCS Energy, WSF Inc., and Winwell Resources.
PetroQuest Energy Inc.
PetroQuest Energy Inc. found a seat on the learning curve for the Arkoma Basin shales and it is going to stay in the saddle as long as the good news keeps coming.
The company is a David among the Goliaths working the Fayetteville on Caney-Woodford plays, small but mighty.
On the small side, the company controls 45,000 net acres in the Woodford, but that’s 65%more than the company had at the end of 2007. It holds more than 18,000 acres in the Fayetteville Shale in Arkansas.
Moving up the scale toward mighty, the company’s properties in the Woodford have 46.9 Bcfge of proved reserves with more than 360 drilling locations on 80-acre spacing. Add it the 936 Bcfge from probable and possible reserves and the number of locations climbs to 2,371, according to a company presentation in January 2009.
In the Fayetteville, the company has 1.2 Bcfge in proved reserves and 200Bcfge addition probably and possible reserves with a maximum 2,310 drilling locations.
Drilling results look mighty good. With 492 wells drilled in the Woodford trend through November 2008, PetroQuest completed 26, or 5%. Among those 26 wells are 10 of the 21 top initial potentials in the play.
As the company learned, it increased the number of frac stages from six per well to 11 per well. At the same time, it increase initial potentials 290%, and it increased its average Woodford initial potential rate by 150% per frac stage.
Its first five wells averaged 2MMcfge/d from the Woodford. Its latest five wells through January 2009 average 5.8 MMcfge/d. Its best well posted an initial potential of 12.5 MMcfge for one day.
During the fourth quarter, the company drilled the PetroQuest 26 with a 4,026-ft lateral for a maximum production rate of 6.4 MMcfg/d, the PetroQuest 28 with a 6,611-ft lateral for 4.05MMcfg/d and the PetroQuest 29 with a 3,909- ft lateral for 1.88 MMcfg/d.
It planned to complete a well with a 7,057-ft lateral early in 2009 but the well encountered mechanical problems after the first two frac stages. PetroQuest repaired the well bore and produced at rates as high as 3.7MMcfg/d. The company planned to complete another 16 stages in the well during 2009.
Currently, PetroQuest’s Oklahoma properties produce approximately 40 MMcfge/d and its Arkansas properties another 9 MMcfge/d.
It participated in 33 non-operated gross wells, 3.03 net wells, in the Fayetteville in the fourth quarter. It has five non-operated rigs working the play.
PetroQuest planned capital expenditures between US $80 million and $100 million for 2009, depending on oil and gas prices, drilling success and completion and facility costs. Like many other companies, it plans to keep capital expenditures below its cash flow.
Well economics are respectable. On its Woodford wells, the company figures a horizontal well cost between $5 million and $5.5 million to get an initial production rate between 3 MMcfge/d to 5.5 MMcfge/d. At a gas price of $4/MMBtu, it generates a 3% return, at $6 gas the return climbs to 15%, at $8 gas it gets a 29% return and at $10 gas the return is 42%.
In the Fayetteville, with 1.4 Bcfge to 3.5 Bcfge in estimated ultimate recovery, a completed well cost between $1.8 million and $3.4 million and a maximum monthly production rate between 1.2 MMcfge/d and 3.5 MMcfge/d $6 gas brings a 9%, $8 gas a 20%return, and $10 gas a 33% return.
Presidium Energy LC
Presidium Energy LC, a Michigan operator, with an aggressive drilling program in the Devonian Antrim shale in Michigan, purchased a position in the Woodford Shale in Oklahoma during 2008.
Presidum, founded and managed by John V. Miller, bought 67,000 gross acres in the Oak Tree Project in Oklahoma from interest owners. A large piece of that deal was the $12 million cash purchase of 36,802 gross, 32,753 net, acres from Aurora Oil & Gas Corp. Aurora said the value of the transaction was more than $15 million, and it retained a 3% overriding royalty interest in the area of mutual interest, which subsequently grew to 71,000 acres.
Miller, a co-founder of Aurora, had been vice president of Aurora from May 1997, until Feb. 29, 2008.
According to Miller, “The company is focused initially on drilling oil prospects from 3-D seismic recently acquired. In the process of drilling wells on oil prospects, data is being gathered on the Woodford Shale in preparation for a planned aggressive horizontal drilling program for Woodford Shale gas. Thus far, five vertical wells have been drilled and casing run for completion.”
The arrangement also took Aurora out from under its financial obligations for the property. William W. Deneau, chief executive officer, said, “Completing this transaction creates a winning solution for all parties involved. It generates greater proceeds for the property than were originally anticipated and extinguishes the litigation associated with our joint venture partner in that project area. This is an ideal resolution to a risky and unproductive asset in our portfolio. Going forward, our 3% overriding royalty interest will allow us to participate in what could be a tremendous upside while eliminating downside risk to our enterprise.”
SH Exploration LLC
The Fayetteville Shale attracted international attention as SH Energy and Chemical Ltd. of Seoul, South Korea, and Eurenergy Resources Corp. joined forces to form SH Exploration LLC, a company devoted to exploration in the popular shale formation in Arkansas.
SH Energy acquired mineral rights to 3,000 acres of leases in Van Buren County from Source Rock Energy of Arkansas LLC, a subsidiary of Eurenergy. On completion of the deal, SH Energy owned 51% of SH Exploration and Eurenergy owned the remaining 51%.
In June 2008, the companies had completed drill pad construction of the first well and started construction of the pad for a second well in a two-well program designed with parallel 3,000-ft laterals at a vertical depth of 1,700 ft. It planned a simultaneous fracture treatment of the wells, according to Prime Income Asset Management.
August 2008 records from the Arkansas Oil & Gas Commission show SH permitted the Chavez 3-8H B-43 horizontal well with a planned vertical depth of 2,000 ft and a measured depth of 5,200 ft in Fayetteville
The commission’s October 10 permit report showed the company had drilled the Chavez 1-8H B-43 horizontal well with a vertical depth of 1,578 ft and a measured depth of 5,574 ft and the Chavez 2-8H B-43 horizontal well to 1,568 ft vertically and a measured depth of 5,672 ft in Fayetteville. The company also permitted the Garner 1-13H B-43 with a planned 1,600-ft vertical depth and a planned 5,300-ft measured depth.
Sedna Energy Inc.
Sedna Energy Inc. is a minor player in the Fayetteville Shale play on the Arkansas side of the Arkoma Basin, but it has a history of operations in other plays in northern Arkansas.
The company is a subsidiary of Dernick Resources Inc. of Houston, which also owns Pathex Petroleum Inc. Sedna permitted one Fayetteville well and completed the well.
According to IHS Energy records, the company drilled the 1- 22HGreen Bay development well in 2007 in OakGrove field. The well reached a vertical depth of 6,330 ft and kicked off horizontally to a total measured depth of 8,910 ft. After perforating at five intervals and fracturing in four stages, the company tested the well for 200Mcf/d of gas. It did not take cores or perform a drillstem test.
Shell Exploration & Production Co.
Shell Exploration & Production Co. likes the potential of production of oil and gas from shales, as long as that potential equates with economic gains.
The company has invested heavily in shale oil research in the massive shale deposits of northwestern Colorado, and it took an early look at the Barnett Shale in north Texas.
It also likes the idea of partnering with knowledgeable operators. It formed a partnership with EnCana in the Haynesville Shale play, and, in 2006, set up a partnership with Pathfinder Exploration LLC in the Fayetteville.
Shell had purchased approximately 70,000 acres of leases with Fayetteville potential from four smaller operators. It put those properties into a joint venture arrangement with Pathfinder with Pathfinder acting as operator on the venture. The companies planned to evaluate the Fayetteville in several Arkansas counties.
In 2007, the SEECO Inc. subsidiary of Southwestern Energy included both Shell and Pathfinder as it sought to unitize a drilling location in White County. Pathfinder has permitted wells in both White and Woodruff counties in Arkansas.
Southwestern Energy Co.
Nearly every play hosts a dominant player, usually the company that saw the potential early, started buying leases in large volumes at low prices and proved up the technology that made the play viable. Southwestern Energy Co. is that company in the Fayetteville Shale.
Longer laterals and increased use of slickwater fracture treatments resulted in higher production rates. (Source: Southwestern Energy Co.)
It drilled its first Fayetteville well in the second quarter of 2004, the first horizontal well in the first quarter of 2005 and conducted the first slickwater frac treatment in the third quarter of the same year.
In a January 2009 presentation, the company said it raised Fayetteville production to 670MMcfg/d by December 15, 2008, more than doubling the 300 MMcfg/d it produced a year earlier.
The company had 716 Bcf in reserves and it still had a lot of wells to drill on its 860,000 net acres with Fayetteville potential.
The Fayetteville operations helped Southwestern post record earnings of US $218.2 million in the third quarter of 2008, up 328% from the same quarter a year earlier.
“This was a great quarter for Southwestern Energy,” said Harold M. Korell, chief executive officer of Southwestern. “Our financial results were outstanding and in our Fayetteville Shale play we continue to see significant improvements in well performance as we implement new completion techniques across the play.”
The company expects its average well to cost $3 million to $3.25 million to completion in 2009.
Those completions feature longer lateral legs on horizontal wells, increasing use of slickwater fracture treatments and larger frac jobs. Well efficiency also benefits from the use of 3-D seismic. That’s the reason Southwestern will use 3-D seismic information on more than 95%of its wells in 2009, up from 70% of its wells in 2008.
Also in 2009, Southwestern plans to use tighter spacing— about 75-ft intervals — on its 2009 wells, and it will lengthen its laterals to an average 3,800 ft.
In previous wells longer laterals gave the company higher production rates.
Southwestern carries its profit potential beyond the drilling and completion phases, as well. By the end of September 2008, the company had put together a gas-gathering system capable of moving 675 MMcf/d of gas over 793 miles. That’s a capacity increase from 250 MMcfg/d in the third quarter of 2007.
The company’s production increase took place even though the company sold 55,631 net acres, or about 6% of its Fayetteville shale holdings, for approximately $518.3 million in the second quarter of 2008. The properties were producing 10.5 MMcf/d of gas when Southwestern sold its holdings.
During a conference call with analysts, Korell said, “The Fayetteville shale disposition was to test the market at that time and really sets us up nicely as we go forward. Having said all of that, which is a disclaimer and backdrop, the future will depend upon gas prices and will depend upon the idea generation activities we have internally, it will depend on how our Marcellus turns out, whether something develops on that acreage where someone’s going to drill a couple wells for us in Haynesville. There are just so many moving variables.”
Final production figures of 2008 could have been higher, but the delay of completion of the Fayetteville lateral of the Boardwalk Pipeline caused a bottleneck in production plans during the quarter. It was scheduled for completion by the end of the quarter. Southwestern has 500,000 MMBtu/d of firm capacity on that pipeline, rising to 800,000MMBtu/day by 2010.
Southwestern also has prepared for future takeaway from the Fayetteville as its midstream services division committed to 1,200,000 dekatherms a day of firm capacity with Fayetteville Express Pipeline LLC when that line starts moving gas in late 2010 or early 2011.
Southwestern also wants to make sure it has new production coming on. It plans to invest $1.5 billion in the Fayetteville shale in 2009, including some $200 million for gathering system expansion. That’s up from $1.4 million and $175 million, respectively, in 2008. The 2009 figure includes some $65 million in well completions deferred because of the delay in completing the Fayetteville lateral on the Boardwalk line.
By the end of the third quarter of 2008, the company completed 722 operated Fayetteville wells, and 652 of those wells were horizontally drilled. It participated in 580 wells in the first nine months of 2008. Of those wells, 327 were successful, 246 still were in progress, and seven were dry holes.
IHS Inc. statistics show results from some of the Fayetteville wells drilled in northern Conway County, Ark., by SEECO Inc., Southwestern’s operating unit. The 1-20H Reyes Salinas 9-15 flowed an initial 5.43 MMcf/d of gas through perforations in a south lateral. The 2-20H Reyes Salinas 9-15 tested for 4.45 MMcf/d of gas. About 1 1/4 miles northeast of the 1-20H well, the company tested 4.42 MMcfg/d initially at its 3-16HMagdalena Salinas 9-5. Some two miles farther east, the 2-14H Gary Stark 9-16 tested for 4.86 MMcf/d of gas.
“In 2009, we will continue to operate 20-21 rigs in the Fayetteville Shale play and, with the improvements in our drilling times, we currently expect to participate in approximately 620 horizontal wells (470 operated), compared to an estimated 520 wells in 2008, as we continue to develop our significant acreage position. As a result of our planned investments, we expect our 2009 production to be in a range of 280 Bcfe to 284 Bcfe, which is an increase of approximately 48%compared to our expected 2008 levels,” said Korell.
St. Mary Land & Exploration Co.
St. Mary Land & Exploration Co. honed completion techniques in the Woodford Shale in Oklahoma to reduce well costs and sharply increase estimated ultimate recoveries.
With 40,000 acres in the popular play, the company ran two to three rigs in the shale during 2008 drilling horizontal wells with 4,000-ft laterals, although at least one lateral reached 4,200 ft. Even after the sharp price depression, the company likes the Woodford and will continue drilling the play during 2009.
Investment plans call for the company to invest within its cash flow. For the Woodford Shale, assuming US $42/bbl oil and $5.30/Mcf gas, the company will dedicate $46 million of its total $350 million capital expenditures to the Woodford wells in the core area in Coal County and in the surrounding McAlester, Bandit, and Ashland field areas.
Current plans call for the company to drop rigs as the contract terms expire and ramp up activity after mid-year 2009 when it hopes to get rigs at lower rates due to a decline in activity.
Estimated ultimate recoveries for the company continue to improve. Its latest 10 wells averaged more than 4 Bcfge with a completed well cost between $4.5 million and $5.5 million. That program was economic in the year-end 2008 environment.
Typically the company’s wells take 30 to 32 days from spud to total depth, but it has drilled as quickly at 25 days and as slowly as 45 days. Spud to sales takes about two months, the company said, and much of the additional time is taken in lining up frac equipment.
In November, St. Mary had completed 24 horizontal wells. Its early wells showed poor results, but the company recovered with more aggressive completions and increased estimated ultimate recoveries sharply from the 2.7 Bcfge to 3 Bcfge it expected early in its operations in the play.
The company’s first quarter 2008 report said it planned 10 horizontal Woodford wells with two operated rigs in the first half of the year, and it participated in non-operated wells.
Storm Cat Energy Corp.
The Fayetteville Shale has shared its bounty with a lot of companies. Unfortunately, Storm Cat Energy Corp. wasn’t one of them.
The company had concentrated its US operations on coalbed-methane wells in the Powder River Basin of northeastern Wyoming, but also tried unsuccessfully to produce coalbed methane in Alaska.
In an effort to diversify, it acquired 18,500 net, 24,500 gross, acres in the Fayetteville play in Van Buren County, Ark. Those properties were near successful operations of Southwestern Energy division SEECO Inc., and Storm Cat planned to work with that company with SEECO as the operator.
It estimated well cost at US $1.8 million. It estimated an unrisked rate of return of 50%, unrisked finding and development costs at $1.10/Mcf of gas, and unrisked reserve potential at 195 Bcf on its Fayetteville properties.
On Nov. 10, 2008, the company said it was unable to make timely payments to creditors and its US subsidiaries filed for protection from creditors while it reorganized under Chapter 11 of the US Bankruptcy Act. A short time later, it obtained court approval to arrange post-petition operating rights.
Later, it obtained court permission to arrange $14 million in financing, and in January, 2009, it was trying to get shareholder approval for that financing.
The company reported a working capital deficit of $139.5 million on Sept. 30, 2008, compared with a deficit of $2 million on Dec. 31, 2007. It had invested $17.8 million in capital for permitting, drilling, completion, repairs, maintenance, and acquisitions in the Fayetteville play.
Its ability to continue operations depends on getting a debtor-in-possession credit agreement with its creditors and the cash to continue operations, the company said.
Talisman Energy Inc.
Canadian energy powerhouse Talisman Energy Inc., leveraging its experience in the Marcellus Shale in New York, bought its way into a solid position in the Fayetteville Shale in Arkansas with Hallwood Energy as a partner.
Unconventional hydrocarbons, with North Sea, Southeast Asia, and global exploration are the company’s focus points, according to an early 2009 presentation, and it plans to spend US $3.6 billion to develop those focus areas.
The company will fund its capital program from cash flow, as many other companies have done following the oil price collapse, and it based its spending plans on $40West Texas Intermediate oil and a $5/MMBtu New York Mercantile Exchange price for gas. That spending should keep production at about the same level as 2008, about 430,000 boe.
Talisman entered an agreement to buy a one-third interest in all Hallwood properties through its FEI Shale LP subsidiary, also known as Fortuna.
Under the agreement made in June 2008, Fortuna took an interest in 350,000 gross acres controlled by Hallwood, and it will earn acreage by subsidizing Hallwood’s drilling costs. By June 30, 2008, it had spent $35 million on the properties.
Acquisition of the full one-third interest in 108,000 net acres in Texas, Arkansas, and Louisiana will take an investment of $125 million by Fortuna over 12 to 18 months. The 2008 agreement between the two companies called for 11 wells on the land with potential for up to 1,000 locations.
“This agreement gives us exposure in a number of areas Where we have not been active, including the deep Barnett and Fayetteville shales,” said John Manzoni, Talisman president and chief executive officer. “We also have a technical services agreement which is a significant part of this deal. Hallwood has a proven track record in the early stage development of shale programs and we will use this to augment our experience in the piloting and development of our unconventional plays.”
The technical services agreement commits Hallwood to provide Talisman and its affiliates with technical and consulting services for a year. Specifically, Hallwood will help Talisman with the development of the Montney sand/silt/shale area of British Columbia and Alberta, the Bakken Shale in Saskatchewan, the Utica and Lorraine shales in Quebec, and the Marcellus Shale in New York and Pennsylvania. Fortuna plans 36 gross horizontal Marcellus wells in New York and Pennsylvania in 2009 and could ramp up to 16 rigs in 2010.
Among the properties in the deal are Hallwood’s 40% interest in more than 43,000 acres in the Barnett/Woodford Shale play in Reeves and Culberson counties in west Texas and Hallwood’s 24,500 net acres in the Fayetteville Shale in White and Faulkner counties in Arkansas. Fortuna could earn 14,000 net acres in those two areas.
Triangle Petroleum Corp.
Triangle Petroleum Corp. of Calgary, Alberta, Canada, and its Triangle USA Petroleum Corp. subsidiary in the US had high hopes for the Fayetteville Shale in the Arkoma Basin, but opportunities moved the shale off the company’s list of top priorities.
In early 2007, the company outlined a four-stage plan for its Fayetteville leases. It would conduct detailed geological assessments, acquire land in the core area, acquire and interpret seismic data, and drill wells. First, it planned to drilled vertical calibration wells, and then it would follow up with horizontal wells.
At that time, it had nearly completed the first two stages with Kerogen Resources Inc. of Houston, a company headed by Ronald Harrell, retired chairman and chief executive officer of Ryder Scott Co.
The companies had properties in Conway and Faulkner counties in Arkansas and were accumulating more leases.
They started the third stage, a 3-D seismic program covering some 24 sq miles in Conway County, and Kerogen, the operator had permitted its first vertical well and contracted a drilling rig. It planned to spud the well in March 2007. That well was scheduled to 6,500 ft, and the venture partners planned a second well in the third quarter that year. The companies also planned to have evaluation work done and start drilling their first horizontal well in the third quarter.
“We believe that our Conway County acreage will emerge as a solid producing area due to the combination of favorable geologic controls and higher reservoir pressures, which enhance reserves potential and deliverability,” said Ron Hietala, Triangle USA president.
The companies entered a new joint venture agreement in October 2007, with plans to build on their 20,000 net, 34,000 gross acres, of Fayetteville properties in Conway, Pope, and Faulkner counties where they each held a half interest. It also included a 52-township area of mutual interest in those three counties and Van Buren County. The agreement was to last three years.
That arrangement committed Triangle to drill and complete on new net horizontal well. It would pay two-thirds of the cost to earn a half interest in the well. Thereafter, all wells would be completed on a 50-50 basis. Triangle also agreed to reimburse Kerogen for some US $458,000 in land costs.
Early in 2008, Triangle committed $7.2 million for one well, acquisition of seismic data, and land acquisition in the Fayetteville Shale.
By April 2008, however, Triangle said it planned to focus near-term exploration activities on emerging shale projects in the Maritimes Basin of Eastern Canada.
“Based upon escalating land prices in the Arkoma Basin and the lack of progress in accelerating its exploration program with its partner in the basin, the company decided to monetize its 10,400-acre non-operated net acres in this project area by selling its position this year. In conjunction with that decision, the company’s unproven, non-producing properties in the Arkoma Basin Fayetteville Shale project were deemed impaired, which resulted in a non-cash impairment loss of $6.5 million during the fourth (fiscal) quarter,” the company said.
In May, Eastern Canada took a higher priority when Ryder Scott Co. estimated original in-place gas resources in Triangle’s Horton Bluff Shale properties on the Windsor block of Nova Scotia at 69 Tcf.
Later company releases and update didn’t even mention the Fayetteville, but Triangle and Kerogen attended the North American Prospect Expo in January 2009, with Fayetteville properties on the sale block.
Unit Corp.
Unit Corp. brought its considerable experience in the Arkoma Basin of Oklahoma and its rig fleet to bear as it drilled its first Woodford Shale wells in 2008.
It completed its first horizontal well in the second quarter of 2008 and followed up with additional wells. A November company presentation said it planned to complete 15 Woodford wells in the Arkoma for US $13 million during the year.
The company held 514.6 Bcfe of proved reserves company wide in 2008, and 22% of those reserves were in the Arkoma Basin.
It held 97,000 gross, 18,100 net, acres of leases in the Woodford Shale in the Arkoma Basin and most of that property was help by the company’s production from other zones in the basin’s stacked pay opportunities. For comparison, Unit held 31,360 gross, 6,556 net, acres in the Woodford play in the Anadarko Basin; 30,300 gross, 15,500 net, acres in the Haynesville Shale play; 200,000 gross, 55,000 net, acres in the Marcellus shale; 27,000 gross, 5,400 net, acres in the Bakken Shale and 23,000 gross, 11,500 net, acres in the Mowry Shale in northern Wyoming.
Most of the Arkoma leases were in Pittsburg and Latimer counties, but it had minor interests in Coal and Atoka counties.
Whitmar Exploration Co.
Whitmar Exploration Co. generates and develops gas and oil prospects and has partnered with some of the most successful companies in the industry on its generated play.
Currently, it holds properties in the Appalachian Basin in the northeastern US, the Uinta and Paradox basins in Utah, the Piceance Basin of Colorado, west central Louisiana, east central Texas, the Big Horn Basin of northern Wyoming, and the Anadarko and Arkoma basins in Oklahoma and Arkansas.
Among those properties, it holds 75,000 acres of leases in the Arkoma Basin, more than any other program area except Appalachia where it holds 160,000 acres. It even started the Arkoma Compression Co. to rent compressors in the Arkoma Basin in 1986 and later sold that company after building it into one of the Mid-Continent’s largest compression companies.
The Fayetteville Shale in Arkansas isn’t a major project area for the company, but it did take out a permit to drill four horizontal Fayetteville wells from a single pad in northern Franklin County, Ark.
At that point, it planned to reach the Fayetteville at a vertical depth of 1,800 ft and drill horizontally to a measured depth of 3,000 ft, according to IHS Inc.
XTO Energy Inc.
The Woodford Shale and the Fayetteville Shale in the Arkoma Basin played important roles in XTO Energy Inc.’s “Year of Acquisitions” in 2008, and they will play important parts in the company’s “Year of Drilling” in 2009.
In a 2009 investor presentation, XTO claimed 160,000 net acres in the Woodford Shale with 40 MMcfg/d of production from wells that range from 2.6 Bcf to 5 Bcf in reserves per well.
The industry-wide Woodford Shale play in the Arkoma Basin produced about 550 MMcfg/d at the end of 2008.
During 2009, XTO plans to work five or six rigs in the play to drill 40 to 45 wells at a cost of US $4.5 million to $5.5 million per well.
Among significant recent wells in the play, the company’s Pale Moon 1-31 and the McClung 8-15H eachshowed an initial potential of 6MMcfg/d. The Churchill 1- 26 came in at 4.5MMcfg/d, the Churchill 1-26 gaged an initial potential of 4.5MMcfg/d, and the Black 2H-17 recorded in initial production rate of 4 MMcfg/d.
On the Arkansas side of the Arkoma Basin, the industry produced about 800MMcfg/d at the end of 2008. XTO, with 380,000 net acres in the Fayetteville, produced 30MMcfg/d from wells with ultimate recoveries from 1.5 Bcfg to 4 Bcfg per well.
The company plans 115 to 125 wells in the Fayetteville in 2009 using seven to eight operated rigs. Wells cost between $2.5 million and $3 million.
Significant initial potential for recent wells in the play include the Johnson for 3.5 MMcfg/d, the McFalls for 3 MMcfg/d, the Thomas for 2.7 MMcfg/d, the Deltic for 2.5 MMcfg/d, the Neiheisel for 2.2MMcfg/d, and the Black for 2 MMcfg/d.
The Woodford and Fayetteville, along with the company’s 280,000 net acres in the Marcellus Shale, its 450,000 net acres in the Bakken Shale and 280,000 net acres in the Barnett Shale will make major contributions to the company’s goal of doubling reserves to 22 Tcfe and doubling production to 3.6 Bcfge/d by the end of 2011.
“If you look at the overall production number, this would be the greatest natural gas company ever built in America,” said Bob Simpson, chairman and chief executive officer of XTO, during a conference call discussing the company’s second-quarter results.
It will spend $1 billion in its Eastern Region in 2009, $800 million in the Barnett Shale and $500 million in the Arkoma Basin and its other Mid-Continent properties. Another $350 million will go into the Bakken Shale, Gulf Coast, and offshore. Its Permian Basin projects will take $300 million, and the San Juan, Raton, Uinta, and Piceance basins will use $250 million, and it will direct the remaining $100 million to exploration.
The activity is stronger than XTO’s drilling pace in 2008. For example, the company had 120,000 acres in the Woodford at the end of the third quarter. At that time, it had six rigs working and completed nine wells in the play.
At the same time, it worked seven rigs in the Fayetteville and drilled 18 wells during the quarter.
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