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.
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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.