Louisiana could see additional jobs, new market prospects and increased tax revenue as a result of export opportunities.
When it comes to natural gas, the United States has been largely an importer. But export is the new game, and Louisiana is emerging as the biggest player.
Cheniere Energy, which owns the Sabine Pass Terminal in Cameron Parish, received the go-ahead in May from the U.S. Department of Energy to export liquefied natural gas to any company not prohibited by law.
That made Sabine Pass, which opened in 2008 as a terminal to take in shipments from overseas, the first bidirectional LNG facility in the country, capable of importing and exporting the super-chilled liquid.
Cheniere announced last fall that it would invest $6.5 billion in the Sabine Pass terminal—located less than four miles from the Gulf of Mexico on the widest point on the Sabine River navigation channel—marking one of the largest capital investments in Louisiana. Construction on the new facility will begin this year, with new, permanent employees being hired in 2014.
The company will open the liquefaction facility in 2015, and the second phase of the project is expected to be completed by the end of 2018. It has already signed three long-term contracts for those future exports.
A few months after that announcement came word that Lake Charles Exports, a subsidiary of Houston-based Southern Union Co. and BG Group, received approval to ship exports from its Trunkline terminal. Trunkline was authorized to import LNG in the late 1970s and opened in 1981.
BG Group is one of the top 10 natural gas marketers in the country, with major interests in the Haynesville and Marcellus shale plays, as well as other production in Louisiana. Southern Union’s preliminary cost estimate to modify its terminal to liquefy about 2 billion cubic feet of natural gas per day is estimated at $2 billion to $3 billion.
Louisiana Mid-Continent Oil and Gas Association President Chris John says it wasn’t too long ago when companies were investing billions of dollars building massive facilities to import natural gas into the state. The business model now is reversed, and companies are remaking their capabilities.
“The need and demand for natural gas in the United States was projected to grow, and we didn’t have enough of it,” he says. “Boy, has that all taken a 180-degree turn. The needle on the natural gas industry has gone from ‘we don’t have enough of it’ to now ‘we’re awash in it.’”
Louisiana Economic Development Secretary Stephen Moret says the state expects to see even more massive capital investment projects associated with the Haynesville Shale announced over the next few years.
“The economic benefits of historically low, stable natural gas prices in Louisiana have only begun to be realized,” he says.
The expanded harvesting of shale formations in Louisiana and elsewhere in the country has led to an oversupply of natural gas, making exports more attractive. Six LNG export proposals around the country currently are awaiting approval from regulators as producers look for ways to move their low-cost gas overseas.
In 2010, the latest year for which statistics are available, marketed production of natural gas reached 22.7 million cubic feet, the highest recorded total since 1973. Storage inventories reached a record 3,847 billion cubic feet. And the average natural gas rig count rose 18% over the previous year, from 799 to 942, according to the Energy Information Administration‘s Natural Gas Annual.
Technological advances in drilling and well-completion techniques continue to push the break-even point of production down, making it economical despite low prices. Even as the focus has shifted away from drilling solely for natural gas, increased interest in drilling the shale plays for oil still results in natural gas as a byproduct, continuing to add to the glut in the market.
Not surprisingly, imports have reached a 16-year low, accounting for just 11% of the nation’s natural gas consumption. At the same time, LNG exports—mostly to Canada—doubled in 2010.
“The main reason for the shift itself has been this big supply growth that is not being met adequately, at least domestically, with a corresponding increase in demand for natural gas,” says David Dismukes, associate director and professor at the LSU Center for Energy Studies. “Right now, we’re at record supply production levels, and the conventional wisdom, at least in the near term, is that those levels aren’t going down. Export becomes the next-best alternative.”
If planned liquefied natural gas conversion projects happen, U.S. exports could have significant impact on world energy politics, with Louisiana likely the biggest player, at least early on.
“It’s good for us,” John says. “The more that we become exporters of natural gas, the more the demand is going to increase, which obviously the price follows. And once the price follows, you’ll see increased activity amongst all of these shale plays. It’s very good for our industry that we are finding different markets, and it’s an incredible turnaround for the United States to be an energy exporter in the field of natural gas.”
The nation could end up exporting as much as one-fifth of its gas, roughly 12 billion cubic feet of gas per day—equivalent to almost 90% of European sales from Russia, the world’s largest exporter, according to the World Fact Book.
Demand for America’s natural gas exports is expected to be high. Japanese imports to replace nuclear power after the Fukushima Daiichi disaster are already at record levels, and the country’s acceptance of new plants is expected to wane. There’s also been a 27% jump in China’s first-half purchases. Western Europe and India continue to rely heavily on imports, particularly from Russia and the former Soviet republics.
At the same time, the world’s spare production capacity shrank about 50% this year as consumption grew, and is projected to continue declining through 2014.
Dismukes says the fact that many entities have been willing to sign long-term contracts years before the export facilities are even operating indicates “there’s a genuine and bona fide interest in this and people are willing to put their money where their mouth is on it.”
What it means for Louisiana is, of course, additional jobs, new market opportunities for in-state producers and additional tax revenue for communities where the export facilities are located, among other benefits.
There also are all those pipelines needed to move the natural gas to the export terminals. John says the industry is already seeing an enormous amount of projects on the book of networking a lot of the plays into major pipelines that are already in existence.
“From a standpoint of surveyors, welders and all of the workforce that is needed to lay pipelines, that is frankly exploding right now across Louisiana and from there, connecting all over the country,” he says. “You are seeing a lot of preparations in anticipation of the growth of all this natural gas. The future is very bright for Louisiana.”
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By Conway Irwin
Controversial estimates of potentially enormous new energy reserves highlighted by energy company strategists have sparked a wave of optimistic forecasts for fossil fuel development.
“We’re very much at the very, very, very beginning of the revolution, and we don’t even see where this is going yet.
“It won’t make sense to talk about unconventional,” Banaszak said. The Energy Information Administration (EIA) has forecast that shale gas’ share of US natural gas supply will rise to 46% in 2035 from 14% in 2009. “Even today it’s already, by some estimates, between 20% and 28% of the natural gas that’s produced in the United States,” Banaszak said.
The Novelty Of Shale Remains
Despite rapid development of the unconventional gas sector in the US, shale as a viable source of gas is still a relatively recent phenomenon. Both the ultimate volume of recoverable reserves, and their impact on domestic and global markets, remain to be seen.
Estimates of natural gas resources available in the United States has risen dramatically in recent years, and upward revisions continue. EIA estimates of potential shale gas resources in the US more than doubled in the agency’s 2011 Annual Energy Outlook from the year before, to 862 trillion cubic feet.
Banaszak compared these rising estimates to previous upward revisions in areas like the deepwater US Gulf of Mexico and Alaska’s Prudhoe Bay. “There’s definitely a pattern, as the industry operates in a new resource area, we learn more about it, we learn to understand it better, and estimates often change,” Banaszak said.
“We’re very much at the very, very, very beginning of the revolution, and we don’t even see where this is going yet. Any idea you have about where this is headed is probably still not fully informed, because we’re just still learning,” said Banaszak.
Unearthing Shale Liquids
The same trends of rising production volumes and reserve estimates may be emerging in liquids-rich onshore unconventional fields.
“It is an area where a lot of progress is being made,” EIA deputy administrator Howard Gruenspecht told AOL Energy.
Gruenspecht highlighted the Bakken Shale, which spans parts of North Dakota, Montana, and Saskatchewan in Canada, and the Eagle Ford in Texas, as among the most prominent of US onshore oil plays. He also noted prospects for the Utica Shale, which spans parts of the US midwest and northeast, as well as Quebec.
The Utica “has not provided significant production growth yet, but there is certainly a lot of talk that this will be a liquids-heavy resource,” Gruenspecht said.
A study by the National Petroleum Council, an advisory group that represents oil and gas industry views, suggested that at the high end of the spectrum, tight “shale” liquids plays in the US and Canada could hold recoverable resource potential of 10-20 billion barrels, and future production may exceed 1 million barrels per day.
But forecasting with any accuracy is as difficult for unconventional liquids as it has been for unconventional natural gas. “It’s very early days”, said president of consultancy Strategic Energy & Economic Research (SEER) Michael Lynch.
The large shale liquids deposits in the US — which Lynch said number “at least a dozen” — could collectively hold 100 billion barrels of oil in place, with around 1-3% recoverable. Even at low recovery rates, with such a large resource base, “1% means 1 billion barrels”, Lynch said. He suggested that each deposit could add 50,000 barrels per day each year once equipment and personnel are available.
And unconventional onshore oil reserve estimates may rise substantially as new discoveries are made and producers hone techniques to extract liquids from tight rock. “You’re going to get more recovery per well, lower costs, quicker times, and so forth”, Lynch said.
“Tight Race” Between Onshore and Offshore
Tapping oil and liquids from unconventional formations has already begun to impact US oil production, which rose in 2009 and 2010 after declining steadily since the mid-1980’s. But other sources of output, such as the deepwater Gulf of Mexico, may be equally important to future domestic production growth.
Oil production in North Dakota has risen sharply in recent years, recently surpassing 400,000 barrels per day, thanks in large part to the Bakken Shale. But “while the trend in North Dakota and the unconventional resources is certainly worthy of note, it does not replace the offshore Gulf, particularly the deepwater,” Gruenspecht told AOL Energy.
US offshore crude production from the Gulf of Mexico averaged 1.6 million barrels per day in 2010, accounting for almost one-third of total US oil production, according to the EIA. “We’re talking in North Dakota about production that’s well less than a third of the federal Gulf of Mexico production,” said Gruenspecht.
The NPC study lists potential recoverable oil resources in the US Gulf of Mexico at the high end of the range at 40-60 billion barrels — three-to-four times its estimates for unconventional “tight oil”. According to the NPC, production from the Gulf could rise to 3 million barrels per day in the near- to medium-term if discovered reservoirs yield commercial volumes and drilling returns to levels of activity seen prior to the 2010 oil spill from the Macondo well.
But Lynch foresees a “tight race” between production growth from US unconventional onshore plays and the deepwater Gulf of Mexico.
For shale liquids, “it seems like there’s a lot of potential, and the obstacles are relatively few”, Lynch said. Such obstacles could include new regulations that limit the use of hydraulic fracturing, or procuring sufficient hydraulic fracturing equipment to drill large numbers of wells.
In the deepwater drilling areas, companies’ push into new areas has the potential to unearth supergiant fields. “When you start talking about billion-barrel fields, that’s a lot of oil. And the implication is that if there’s one billion-barrel field, there are probably a lot more 400 million barrel fields,” he said.Related Articles
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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.
Public hearing set on use of ‘fracking’ to extract oil
By AMY WOLD Advocate staff writer Published: May 2, 2011
An oil-rich shale beneath parts of the Baton Rouge area could soon be tapped on a large scale through hydraulic fracturing, a technique that has raised environmental concerns elsewhere.
High oil prices have made hydraulic fracturing, or “fracking,” an economically feasible way to extract oil and gas that in the past were too difficult to get at.
Environmentalists and some people living near such drilling contend fracking pollutes the air, contaminates water and overtaxes water resources — claims the industry argues are unfounded.
The state will hold a public hearing as early as June on whether to approve a drilling production unit in the Tuscaloosa Marine Shale near Ethel in East Feliciana Parish. Devon Energy, based in Oklahoma City, wants to use fracking, said James Welsh, commissioner of the Louisiana Office of Conservation.
“This will be Louisiana’s Eagle Ford,” Welsh said referring to a shale area in Texas that has seen a recent boom in production.
Devon Energy spokesman Tony Thornton said it’s too early for the company to talk about the permit application.
Fracking was employed on one of the four wells already drilled in the Tuscaloosa Marine Shale. But Devon Energy’s proposal marks the start of what is expected to be intensive fracking in the shale.
Madhurendu Kumar, director of the state Office of Conservation’s geological oil and gas division, said Devon Energy’s application for a production unit shows the company believes the area around the well contains multiple leases. It’s a first step toward greater development of the shale, he added.
Since 2008, “fracking” has occurred mainly in north Louisiana’s Haynesville Shale for extracting natural gas. In the Tuscaloosa Marine Shale, the target is oil.
The Tuscaloosa Marine Shale stretches about 200 miles east to west and is about 45 miles wide. A 1997 LSU study estimates there is 7 billion barrels of oil in the shale, Kumar said.
Hydraulic fracturing involves drilling down to the shale layer, then horizontally across the shale. The horizontal pipe is punctured so a high-pressure water/chemical mix can crack the shale, allowing oil or gas to be collected.
The liquid forced into the shale contains a propping agent that helps hold the fractures open, Welsh said. It also can include chemicals that kill bacteria in the water or prevent corrosion and deposits in the pipe. The formulas vary depending on what is needed at each well.
The chemicals that producers use are considered proprietary. The U.S. Environmental Protection Agency has started requesting that information as part of an upcoming study. Some companies have released the makeup of their fracking liquid, while others have resisted.
Barry Kohl, an adjunct professor of geology at Tulane University, said reports from across the country suggest that problems exist with hydraulic fracturing, including water contamination.
“The chemicals they use are secret formulas that they won’t release even to EPA,” said Kohl, who said he worked in the oil industry for 26 years.
Another concern is that the large volume of water needed for the fracking process will deplete underground aquifers or draw down lakes and streams, Kohl said.
Welsh said the state conservation office encourages companies to use surface water when possible, and 72 percent of the water used in the Haynesville Shale comes from such sources.
Some wells rely on the Red River alluvial aquifer, which is very mineralized and doesn’t make good drinking water, he added.
“But it makes wonderful ‘frack’ water,” Welsh said.
Other concerns include air pollution from production, management of the water that comes back out of the well, and noise and vibrations caused by the fracking process.
Welsh counters that hydraulic fracturing has been used in the state for decades without a problem. He said it’s impossible fracking would harm ground water in Louisiana because almost two miles of earth separates drinking water aquifers from fracking activities.
Underground water supplies lie about 2,500 feet below the surface, while the Tuscaloosa Marine Shale is 12,000 to 13,000 feet deep, he said.
When a well is drilled, several casings are installed to prevent any fracking liquid, oil or gas from migrating from the well itself, he said.
“So you have a seal of surface casings,” Welsh said. “It’s our job to see that the drilling that is done is safe. That’s our job. That’s what we do.”
Kohl said another concern is the fracturing process itself.
Fracking wells are similar to injection wells used by industry to dispose of hazardous materials deep underground, Kohl said. Those injection wells have leaked in the past, which means the same could happen with hydraulic fracturing wells.
Without careful planning, Kohl said, it’s possible some high-pressure wells could hit Louisiana’s geologic faults.
If that happens, he said, material pumped into the wells could migrate up through the faults and other cracks to the drinking-water level. Natural gas could seep to the surface, possibly contaminating small streams, he said.
“Those are the sorts of things, from a geologic perspective, that I can see that one has to be very cautious about,” Kohl said.
Kohl contends the push to extract natural gas and oil in marine shale deposits has accelerated so quickly — fueled in part by higher prices — that it’s been hard for states to stay ahead of the game by adopting more-stringent safety regulations.
The state’s argument that no water-contamination problems have stemmed from fracking in the past holds little comfort, he said.
A recent review of Louisiana’s hydraulic fracturing procedures contained both praise and recommendations for improvement.
The State Review of Oil and Natural Gas Environmental Regulations — a nonprofit group that helps states examine oil-and-gas environmental regulations — reported the strengths of Louisiana’s oversight include water-use monitoring requirements rule changes that let producers to reuse fracking liquid to reduce water use.
The group suggested that the Office of Conservation review casing and cementing standards with an eye toward protecting drinking water.
Another recommendation is having producers report to the state the amounts of all chemicals used in fracking.
The U.S. Environmental Protection Agency is conducting a study into the impacts of hydraulic fracturing. Preliminary results could be made public by the end of 2012.
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Louisiana Hydraulic Fracturing State Review, March 2011