St. Helena well’s initial production spurs interest
The Encana Weyerhauser well, completed in November, averaged 784 barrels of oil per day and 309,000 cubic feet of natural gas, according to Encana’s filing with the state Department of Natural Resources.
“This is certainly a key well. There’s no doubt,” said Dan Collins, a Baton Rouge landman who spent much of last year negotiating lease agreements with landowners in the shale.
“You know, 800 of anything coming out of the ground daily is a lot,” Collins said.
That’s especially true when the anything in question fetches nearly $100 a barrel.
Around two dozen wells have been drilled or are being drilled in the Tuscaloosa Marine Shale, an oil-rich formation that covers Louisiana’s midsection. Energy companies have leased more than 1 million acres in the formation, but so far the firms aren’t sharing much of their early production figures.
Kirk A. Barrell, president of Amelia Resources, of Texas, said before the formation can be considered economically viable, 10 to 20 wells will have to be completed.
“You need the initial (production) rates for 10 to 20 wells, but you also need to get 12 to 15 months out and see what the decline of that rate is,” Barrell said.
Still, Collins said it appears the energy companies believe they have something.
Oil companies have proposed a number of wells and discussed putting multiple drilling pads on landowners’ property, Collins said. The shale’s future remains to be seen, but there probably wouldn’t be so much activity if the energy companies didn’t believe their investment is worthwhile.
Encana has leased around 270,000 acres in the play, has completed one horizontal well, and has two new wells under way, according to its investor presentations.
Encana spokesman Alan Boras said he could not discuss any details of the company’s Tuscaloosa wells.
But the company will release more information during its fourth-quarter earnings report, scheduled for Feb. 17, Boras said.
A lot of people think every well in the Tuscaloosa should produce 1,000 barrels a day, but it takes time for drilling companies to figure out the best approach, Barrell said.
Barrell, the author of a blog on the Tuscaloosa Trend, said people forget or don’t realize that the early results varied from wells drilled in the Eagle Ford Shale in Texas.
While there were a few good wells whose maximum production was around 1,000 barrels per day, there were a number of wells whose daily production never reached double figures, Barrell said.
Collins said in order to recover the millions in drilling costs, a well’s initial production has to be pretty strong because the production curve declines pretty rapidly.
Shale wells’ production rates generally fall about 75 percent after 12 months.
“I liken it to a ski slope. We certainly don’t want the black ski slope. We want one of those greens or blues that’s going to … gently drop over time,” Collins said.
Gifford Briggs, vice president of the Louisiana Oil and Gas Association, said the Encana well’s results will encourage additional testing.
But it’s difficult to say how significant the well is without knowing the costs and how long the well will continue producing at the same rate, Briggs said.
In this early phase, Encana and other companies operating in the Tuscaloosa are still trying to answer a number of questions, such as what is the right depth to drill and how to get the most effective fracture, he said.
Wells in the Tuscaloosa are drilled vertically for around 11,000 feet and then horizontally. Drillers then fracture the formation in multiple stages, forcing millions of gallons of water, mixed with sand and/or ceramic and chemicals into the formation to crack the shale. The sand and ceramic materials prop the cracks open, releasing the oil.
Fracking has drawn criticism from environmentalists and some landowners, who say the practice pollutes the air, contaminates water and consumes too much water. The oil and gas industry’s position is that fracking has been used for more than 50 years on thousands of wells with no evidence of groundwater pollution.
Collins said leasing activity in the area has slowed this year as companies have turned to drilling, but Barrell said his firm and its partners are still actively leasing.
Lease prices in the Tuscaloosa Marine Shale, compared to other shale plays, remains a “great, great value,” Barrell said.
Last year, leases were going for around $150 an acre.
Briggs said he has heard that leases are fetching $250 to $500 per acre.
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WASHINGTON, DC, Aug. 31
By Nick Snow
OGJ Washington Editor
Oil and natural gas producers have begun work on developing a third shale play in Louisiana, giving the state one proved and producing formation and two that are being watched closely, according to Scott Angelle, secretary of Louisiana’s Department of Natural Resources.
The new area in northern Louisiana and southern Arkansas is referred to as the “Brown Dense” or “Lower Smackover” and is believed to be a limestone layer at the base of the Smackover formation, a long-time source of traditionally producer oil and gas in northern Louisiana, Angelle said Aug. 31.
He said the Brown Dense joins the Tuscaloosa Marine shale as the second half of a Louisiana dense-rock play duo believed to have production potential similar to Louisiana’s Haynesville shale and the Barnett and Eagle Ford shales in Texas. The Tuscaloosa Marine shale is believed to underlie much of central Louisiana, with exploration under way in areas from Vernon Parish to East Feliciana Parish, Angelle said.
He said initial development of the Brown Dense—generally believed to underlie northern Claiborne, Union, and Morehouse parishes—has barely begun. Southwestern Energy Co., Houston, has begun to drill its first well in the Brown Dense in Arkansas, and has announced it will seek a permit to drill a second in Claiborne Paris by yearend 2011, Angelle said (OGJ Online, July 29, 2011).
In Southwestern’s second-quarter earnings teleconference on July 29, the company’s Pres. and Chief Exeuctive officer Steve Mueller said the company had, to date, invested $150 million, or $326/acre, on undeveloped Brown Dense acreage, with an 82% average net revenue interest. “We’ll begin by targeting the higher gravity oil window under our lease, which we believe could be 45-55° gravity range,” he said.
The right mix
Southwestern has reviewed the Brown Dense extensively across the region and has indications that it has the right mix of reservoir depth, thickness, porosity, matrix permeability, ceiling formations, thermal maturity, and oil characteristics, Mueller stated.
The area’s porosity is 3-10% and it has an anticipated 0.62 psi pressure gradient, making it overpressured, he said.
“We have assembled log data on 1,145 wells covering five states to evaluate the Brown Dense and acquired over 6,000 miles of 2D seismic and have gathered and analyzed rock data from cores and cuttings from 70 wells that penetrated the Brown Dense zone,” Mueller said. “At this point, we currently have more data about the Brown Dense than we had on the Fayetteville shale when it was announced.”
He said Southwestern hopes to spud its first Brown shale well in Arkansas during the third quarter and the second, in Louisiana’s Claiborne Parish with a planned vertical depth around 8,900 ft and a 3,500 ft planned horizontal lateral, later this year.
“We plan to drill up to 10 wells in 2012 as we continue to test this concept,” said Mueller. “This formation has sourced several large conventional oil and gas fields and our hope is to use horizontal drilling technology to unlock at least as much potential. Positive test results could significantly increase our activity in this play over the next several years.”
Angelle said Devon Energy Corp., Oklahoma City, also has acquired 40,000 acres in the Brown Dense and plans to drill a test well there. The independent has received a permit for a well targeting the deeper Smackover in Morehouse Parish, the Louisiana official said.
He said that Devon also is active in the Tuscaloosa Marine shale, with 250,000 acres leased, and plans to drill two wells. About a half dozen wells targeting the Tuscaloosa Marine—long thought to contain substantial reserves, but previously considered uneconomical—are currently in the process of being drilled or securing permits, Angelle said.
The increased activity will create more water demand for hydraulic fracturing, noted another Louisiana official, State Conservation Commissioner Jim Welsh. The decline in water use in the Haynesville shale play, however, may more than offset the increase in water use in the Tuscaloosa Marine and Brown Dense, at least in their early stages.
Producers drilling in the Brown Dense formation have informed the state’s conservation office that they intend to use surface and recycled water for their overall project needs, in conformance with guidelines issued for nearby areas experiencing stressed groundwater conditions, he said.
The anticipated Brown Dense development area underlies the Sparta Aquifer, where water levels have recently improved following combined state and local efforts to manage groundwater use, Welsh said. “We are still discouraging new high-volume users from using groundwater in that area, and are giving guidance for alternative sources for water,” he added.
If 2008 was the Year of the Shales, 2011 is shaping up to be the Year of Liquids-Rich Plays–and there are still four months to go.
A major recurring theme in second-quarter conference calls was oil companies’ news of positions amassed or initial test wells drilled in new shale and unconventional fields containing oil and natural gas liquids.
Plays such as the Tuscaloosa Marine Shale, Mississippi Lime, Lower Smackover/Brown Dense and Utica shales–both in Ohio and to the west in Michigan–are lining up to be the emerging fields of 2012 and 2013, analysts said.
“We’ll see a movement in some of these plays and it’s not going to slow down–if anything, it will be a pretty tight market for services, fracturing crews and pipeline access,” Michael Bodino, head of energy research for Global Hunter Securities, said.
Arguably, the Utica Shale was the showpiece of the quarter, particularly because its cachet resembles that of Northwest Louisiana’s giant Haynesville Shale, which took Wall Street by storm when Chesapeake Energy trumpeted it in March 2008.
Chesapeake again took the lead in showcasing the Utica late last month, relating the news that the play economically “looks similar, but is likely superior to the Eagle Ford Shale in South Texas…because of the quality of the rock and location of the asset” near eastern US population centers, CEO Aubrey McClendon said.
Like the Eagle Ford, which stands out as one of the US’ most sizzling shale plays at present, the Utica has oil and “dry” natural gas and “wet gas” (gas liquids) windows, he said.
Jeff Ventura, chief operating officer at Range Resources, which pioneered the Marcellus Shale in Pennsylvania, said his company already has drilled two Utica wells. At least on its acreage, Utica is at the bottom of a pancake stack of three play zones, with the Upper Devonian Shale on top and the Marcellus in the middle. The Upper Devonian shales contain about as much gas in place as the Marcellus zone, Ventura said, adding that the Marcellus gas field has been called one of the US’ largest.
Both Range and Chesapeake also have scored success in Northern Oklahoma’s Mississippi Lime play. “In the past year it has become more clear that we have a major play on our hands,” said McClendon, with Chesapeake holding 1.1 million acres there, running six rigs, aiming for 10 rigs by year-end and 30 to 40 by end-2014 or 2015.
Range’s Ventura suggested the play, found at relatively shallow depths of 5,000-6,000 feet, is also highly profitable; it boasts a 100% rate of return at $100/b oil, and he added that even at $90/b it yields a roughly 80% return. Range, which has completed seven horizontal wells, sees its main near-term activity there as nailing the optimal lateral length and well spacing.
Ventura said liquids make up 70% of a well’s recoverable hydrocarbons. McClendon estimated 415,000 barrels of oil equivalent per well, at an average finding cost to date of roughly $11/b, which he called “very, very attractive results.”
Meanwhile, in its late July conference call, Southwestern Energy CEO Steven Mueller said his company has acquired 460,000 net acres in an unconventional horizontal play targeting the Lower Smackover Brown Dense formation.
“This happens to be almost the exact same number of acres we had when we announced the Fayetteville Shale play back in August 2004,” Mueller said. That news kicked off an industry rush to that gas play, Mueller said.
But having reviewed the results of more than 70 wells that penetrated the Brown Dense zone, “we currently have more data about [it] than we had on the Fayetteville Shale when it was announced,” he said.
Mueller said the Brown Dense is an oil reservoir in Northern Louisiana and Southern Arkansas, at 8,000-11,000 foot depths and below the Haynesville Shale which is also a gas play. Brown Dense is “extensive over a large area and ranges in thickness from 300 to 530 feet,” he said.
Southwestern plans its first Smackover/Brown Dense well in Columbia County Arkansas, before the end of September, with a second well later in the year in Claiborne Parish, Louisiana.
In addition, Goodrich Petroleum in early August said it had begun drilling the Buda Lime, beneath the Eagle Ford. The small company averaged a respectable 900 boe/d oil from those wells, against 800 boe/d from its 11 Eagle Ford wells so far.
Rob Turnham, Goodrich chief operating officer, also touted the Tuscaloosa Marine Shale, along the horizontal Mississippi-Louisiana border, where both Encana and Devon Energy have large positions and are drilling wells. Tuscaloosa “has a lot of similarities to the Eagle Ford–similar permeability and porosity” of the rocks, he said. Goodrich will begin drilling in early 2012.
He said nine older wells in the play have flowed oil but “none of them have been properly stimulated.” If the vertical wells were to be taken horizontally several thousand feet, fractured with current technology, and properly stimulated, “we’re very optimistic,” said Turnham.–Starr Spencer in Houston
By Peter Staas 8/11/2011
As the shale oil and gas revolution has picked up steam over the past several years, several important trends have emerged that will separate the winners from the losers.
The combination of depressed natural gas prices in North America and robust oil prices has prompted independent producers to ramp up drilling activity in fields rich in oil, condensate and natural gas liquids (NGL) while reining in operations in Louisiana’s Haynesville Shale and other dry-gas plays. By many accounts, natural gas production has become incidental to these higher-value hydrocarbons.
Besides focusing on a company’s production mix, investors must also evaluate the economics and quality of a producer’s acreage. first movers in oil- and liquids-rich plays have the opportunity to snap up the best acreage at a fraction of the costs incurred by late entrants.
For example, Marathon Oil Corp (NYSE: MRO) recently paid $3.5 billion for 141,000 acres (about $21,000 per acre) in the Eagle Ford Shale from Hilcorp Resources Holdings LP. The deal surpassed the $16,000 per acre that Korea National Oil Corp paid to Anadarko Petroleum Corp (NYSE: APC) to establish a foothold in this liquids-rich shale play.
The elevated prices that latecomers have paid for acreage illustrate the importance of being an early mover in these plays. This strategy has paid off for EOG Resources (NYSE: EOG), the leading oil producer in North Dakota, the Eagle Ford Shale and the Niobrara Shale. Lower entry prices translate into more financial flexibility and superior margins for producers that snap up the best acreage at pre-boom prices.
Readers of The Energy Strategist can attest to the importance of focusing on early movers that have acquired the best acreage.
My colleague Elliott Gue added Petrohawk Energy Corp (NYSE: HK) to the publication’s model Portfolio on May 10, 2010, citing the company’s acreage in the Eagle Ford Shale, a liquids-rich field in South Texas that the firm discovered in 2008. The stock represented a compelling value at the time; investors had overlooked this asset and the potential for the firm to grow its liquids output, focusing instead on its leasehold in the Haynesville Shale and exposure to natural gas prices. Elliott also highlighted the stock as one of his top takeover targets of 2010.
A year later, Elliott’s investment thesis panned out: Australian mining giant BHP Billiton (NYSE: BHP) announced that it would acquire Petrohawk Energy in an all-cash deal worth $12.1 billion. Readers who followed Elliott’s call booked a 92 percent gain.
With these advantages in mind, producers are constantly on the lookout for the next liquids-rich shale play that offers attractive margins. Here’s a brief rundown of some of the emerging shale plays in which North American producers have accumulated acreage.
1. Tuscaloosa Marine Shale
In recent quarters, a handful of independent exploration and production (E&P) outfits have touted their acreage in the Tuscaloosa Marine Shale (TMS), a formation that stretches from Texas to Louisiana and Mississippi. The field is far from a new discovery; famed Mississippi wildcatter Alfred Moore spearheaded drilling in the TMS in the 1960s.
The play’s proximity to the Haynesville Shale should make it easier for producers to redirect drilling rigs from the out-of-favor dry-gas play and limits bottlenecks associated with a lack of midstream infrastructure. Despite boasting similar geologic characteristics to the Eagle Ford, the TMS is far from a slam dunk, which explains the low prices that early movers have paid to build an acreage position.
Goodrich Petroleum Corp (NYSE: GDP), for example, amassed about 74,000 acres, paying an average of $175 per acre. Meanwhile, Devon Energy Corp (NYSE: DVN) has accumulated 250,000 acres on the Louisiana-Mississippi border at an average cost of $180 per acre.
Thus far, early movers in the TSM have yet to report drilling results, though management teams have indicated that these tests have been encouraging. Devon Energy recently completed drilling, coring and logging its first vertical well in the play and plans to sink its first horizontal well later this year. Denbury Resources (NYSE: DNR) and its partner EnCana Corp (TSX: ECA, NYSE: ECA) are at a similar stage in their drilling program and plan to sink a horizontal well in September.
During EnCana’s conference call to discuss second-quarter results, Executive Vice-President Jeff Wojahn described its TMS assets as “a promising liquids-rich opportunity” based on “how the rock breaks, the hydrocarbon content and gas in place, and the like.” Management also pegged the drilling costs for its first horizontal well–a 12,000-feet deep vertical shaft with a 7,500-foot lateral segment–at about $8 million.
We’re very comfortable today with what we see from a geologic standpoint of going ahead and drilling wells. In fact we don’t really even see much need, at least in most of our acreage, for pilot holes. There [are] sufficient amounts of historical vertical wells that have been drilled through the Tuscaloosa Marine Shale that we’re comfortable going out and drilling today. I would characterize at least in our view that the sole or the largest single risk to the play is just one of the economic performance versus well costs. We know the Tuscaloosa is present, sufficiently thick, thoroughly oil saturated. It’s just a little unproven in that no one has drilled yet a well that’s demonstrated in the EUR horizontally that would match up to costs. And that’s just [be]cause there haven’t been really many or any of them out there that have done that.
Drilling results in this frontier play could provide a meaningful upside catalyst for these E&P operators. At the same time, if the play proves uneconomic to produce or drilling results disappoint, the low cost of acreage provides a degree of downside protection.
2. Utica Shale
Management teams from several E&P firms also touted the potential of the Utica Shale, a formation that lies beneath the Marcellus Shale but extends from Tennessee into Canada. Thus far, the Marcellus has attracted the most attention from investors and producers, though interest has picked up in the Utica–particularly the shallow portion in Ohio and Western Pennsylvania.
For example, Devon Energy has assembled an 110,000-acre leasehold in the play’s oil window and recently noted that a vertical test well indicated that the formation features excellent permeability. During Devon Energy’s conference call to discuss second-quarter results, the head of its exploration and production operations noted that the play’s oil window “could offer some of the best economics in the play.”
CEO Aubrey McClendon and his team at Chesapeake Energy (NYSE: CHK) likewise highlighted the firm’s position in the Ohio portion of the Utica during the company’s July 29 conference call. One of the first movers in the play, Chesapeake quietly amassed 1.25 million net acres–by far the largest position in the field–and drilled some of the first test wells, including nine verticals and six horizontals. Over this period, the company has also analyzed 3,200 feet of core samples and more than 2,000 well logs.
McClendon compared this portion of the Utica Shale to the Eagle Ford in South Texas, noting that the field includes three phases: a dry-gas zone in the east; a wet-gas window in the middle; and an oil-rich phase on the western side.
The outspoken CEO boldly suggested that the emerging field would generate better returns than the red-hot Eagle Ford: “[W]e believe the Utica will be economically superior to the Eagle Ford because of the quality of the rock and location of the asset.”
Not only is much of the company’s acreage already held by production, but the relative shallowness of these oil and gas reserves should limit drilling costs. Although management demurred from sharing well results, McClendon did indicate that his team was sufficiently encouraged to ramp up the rig count from one at the beginning of 2011 to eight units by year-end. At the same time, the play will require a substantial investment in midstream infrastructure to process and transport the oil, NGLs and natural gas to market.
3. Neuquen Basin
In The Future of Shale Gas is International, we opined that major international oil and natural gas companies were investing heavily in US shale plays to gain experience that would translate to fields outside the US. Argentina’s Neuquen Basin is home to one of the most-promising international shale oil plays.
Spanish energy giant Repsol (Madrid: REP, OTC: REPYY) in July announced that its Bajada de Anelo X-2 exploration well had yielded 250 barrels of oil per day from the Vaca Muerte shale formation.
US operator EOG Resources added 100,000 acres in the Neuquen Basin to its exploration portfolio in the second quarter and plans to sink two wells in this acreage in early 2012. During a recent conference call, CEO Mark Papa noted that he expected results from the play to help operators overcome a lack of hydraulic fracturing and other equipment in the country:
[T]he major service companies are in a process of shifting additional frac [hydraulic fracturing] equipment down there, and for the first couple wells, it’s going to be kind of one-off deals that we’ll have to schedule months and months in advance to get the fracs done. But our logic is if this shale turns out to be something that is commercial and productive, that you’ll see, particularly the major service companies, just move equipment in there in a 2013 through 2015 time frame. We’re pretty optimistic about the quality of that shale. We charged our people with the only way we’d go outside North America is if we could find a shale–an oil shale that we thought looked superior to the Eagle Ford, and we believe we’ve found one there. So time will tell.
By TED GRIGGS Advocate business writer Published: May 6, 2011
A third independent, Amelia Resources LLC of The Woodlands, Texas, has signed a deal with an unnamed partner to help develop the more than 110,000 acres Amelia has under lease.
Devon Energy officials said Wednesday the Oklahoma City-based company has leased around 250,000 acres in the shale. Devon plans to drill two wells in the formation this year, the first of them this quarter.
On Thursday, Dallas-based Denbury Resources announced a joint venture with an unnamed partner that will complete one well and drill another at no cost to Denbury. In late 2009, Denbury acquired Encore Acquisition Co., which had drilled some wells in the shale.
In a news release, Denbury Chief Executive Officer Phil Rykhoek said the company will retain a small interest in future activities in the shale.
“We continue on our oil-focused program and expect many good things in the near future,” he said.
LSU researchers have estimated the Tuscaloosa Marine Shale holds 7 billion barrels of oil.
During Wednesday’s conference call with stock analysts and investors, Devon Executive Vice President of Exploration and Production David Hager said the formation lies 11,000 to 14,000 feet underground and is 200 feet to 400 feet thick.
Hager said Devon believes it can use fracturing technology — pumping in water, sand and chemicals to crack the shale — to increase production in the formation.
The state plans to hold a hearing, possibly by next month, on whether to approve Devon’s request to use hydraulic fracturing for a well near Ethel in East Feliciana Parish. “Fracking” has drawn criticism from environmentalists who say the process contaminates the water supply and places a heavy burden on the resource. The oil and gas industry says those claims are inaccurate.
Hager said vertical wells drilled in the formation had initial production rates of 300 barrels per day.
The three or four horizontal wells drilled in the shale three years ago, which were shorter than Devon plans to drill, tested at rates of up to 500 barrels per day, Hager said.
Those are all reasons for encouragement, Hager said. But Devon needs to get more information on the oil play, including whether the formation can be fractured, and there are risks associated with Devon’s investment.
Still, the company has spent less than $50 million on its leases, and if Devon is successful the company “can create an awful lot of value,” he said.
Kirk Barrel, president of Amelia Resources, said drilling a longer horizontal segment, or lateral, exposes the wellbore to as much rock as possible, and that means the well can produce more oil.
Barrel, author of a blog on the Tuscaloosa Marine Shale, said one of Encore’s wells was drilled horizontally out to 4,100 feet; a typical horizontal section is 4,000 to 5,000 feet long.
However, in the two wells it fractured, Encore only did three stages, Barrel said. Devon’s plans show the company plans to do 13- to 15-stage fracks, which in theory should substantially increase production.
In the south Texas Eagle Ford Shale, “a distant cousin” geologically of the Tuscaloosa Marine Shale, some drilling companies have done 20-stage fracks, Barrel said. In North Dakota’s Baaken Shale, some wells have had 40-stage fracks.
Matt Ross, a spokesman for the Louisiana Oil and Gas Association, said in multistage fracturing, the initial fracturing is done around the point where a well levels out horizontally.
The subsequent fracks are spaced throughout the rest of the horizontal section, Ross said. The spacing depends on the drilling company’s preference.
Meanwhile, Barrel said his firm has placed a significant amount of acreage with an unnamed partner.
Barrel said he could not disclose how much acreage Amelia now has under lease; in February that was more than 110,000 acres.
Amelia is still in the process of adding to its acreage, Barrel said, and he did not know when the partnership might begin drilling.
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