By MARILYN ALVA, INVESTOR’S BUSINESS DAILY Posted 01:41 PM ET
U.S. oil production is enjoying a renaissance, thanks to new technology that has made oil recovery possible in tight shale rock.
The Eagle Ford in South Texas and the Barnett “combo play” (gas and oil) in North Texas are also fairly famous unconventional plays.
But the Wolfcamp Shale?
“Over the next two or three years, everybody is going to be making a beeline to the Wolfcamp,” said Scott Sheffield, chief executive of Pioneer Natural Resources (PXD).
Spanning numerous counties across West Texas, the Wolfcamp formation is located below the long-plied Spraberry field, which helped make Midland, Texas, oil-central starting in the early 1950s.
Its location in the Midland Basin is within the larger Permian Basin.
Sheffield and other oil experts say the Wolfcamp is probably the thickest of any onshore U.S. oil shale play, with up to 1,000 feet of potential payout across hundreds of thousands of acres.
Biggest And Thickest
“It will be the biggest, and it is already the thickest,” Sheffield said. “So it’s got the most pay zones of any oil shale play in the U.S. I call it the third or fourth coming of the boom in West Texas.”
If Wolfcamp does turn out to be the next big oil shale play, Pioneer is on the ground floor. With 900,000 acres under lease in the Spraberry, it has the largest land position.
Pioneer believes that more than 400,000 of those acres are ripe for horizontal drilling.
Its game plan: drill 10,000 feet down through the Spraberry to the Wolfcamp and then out 7,000 feet horizontally.
For now, it’s targeting 200,000 acres in the southern portion of the Spraberry field.
Pioneer’s two completed wells in the Wolfcamp have already exceeded expectations, each producing 800 to 1,000 barrels of oil a day, and they’re still early in production.
EOG Resources (EOG) started drilling in the Wolfcamp earlier and is now seeing higher output from its 35 or so wells.
But Sheffield says Pioneer will be a bigger operator in the Wolfcamp in the sense that it has 400,000 prospect-worthy acres to EOG’s 100,000.
“We are going to drill 80 wells in 2012 and 2013,” he said.
EOG’s wells in the Wolfcamp are producing 2,000 barrels a day, says Dan Morrison, analyst with Global Hunter Securities.
“Even if Pioneer’s don’t get to 2,000 barrels a day, at 800 barrels a day the play is incredibly economic,” Morrison said.
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The company is one of only three that holds a federal lease to research oil shale energy development on the Western Slope, but officials say they would rather pursue other projects.
“Chevron has notified the Bureau of Land Management (BLM) and the Department of Reclamation, Mining and Safety (DRMS) that it intends to divest its oil shale research, development and demonstration lease in the Piceance Basin in Colorado,” the company announced Tuesday. “While our research was productive, this change assures that critical resources — people and capital — will be available to the company for other priorities and projects in North America and around the globe. We will work with the BLM and DRMS to determine the best path forward, timing and other issues.” Despite nearly 100 years of failed attempts to make oil shale commercially viable, House Speaker John Boehner, R-Ohio, has said the energy source will help fund his $260 billion transit package and U.S. Rep. Doug Lamborn, R-Colorado, is pushing the Pioneers Act, which would revive a 2008 plan put together during the Bush administration to open 2 million acres of public lands in Utah, Wyoming and western Colorado to oil shale drilling. The House passed Lamborn’s bill this month.
The Congressional Budget Office issued a report, however, which projected that Boehner’s bill would, over 10 years, leave the highway trust fund $78 billion in the red, and the Interior Department is looking at slashing the amount of land available for oil shale research to 462,000 acres.
“Chevron’s research hardly got started and they quickly concluded that they were throwing money down a rabbit hole. It’s indicative of the fact that oil and gas companies see much more profitable, and realistic, opportunities elsewhere,” said Colorado energy expert Randy Udall.
Squeezing energy out of oil shale requires immense quantities of water. Industrial-scale oil shale development could require as much as 150 percent of the amount of water the Denver Metro Area consumes annually, according to Bureau of Land Management estimates.
As early as 1921, oil companies have been trying to tap northwest Colorado for oil shale. The expense required to develop the energy source, however, has outweighed potential profits. About a dozen different projects have come and gone during that time — none remembered more than “Black Sunday” when ExxonMobil pulled the plug on a huge oil shale operation in western Colorado in 1982 that left the region in economic shambles.
Chevron and its subsidiaries started amassing acreage in Colorado for oil shale research back in the 1930s.
“Oil companies have been trying to pull the sword from the stone for nearly a century. Oil shale has no King Arthur,” said Matt Garrington of the Checks & Balances Project. “Chevron’s decision to pull out of oil shale is yet another reason why [U.S. Rep. Scott] Tipton [R-Colorado] and Lamborn should quit saying that melting rocks into oil will somehow fund critical repairs to our roads and bridges.”
Royal Dutch Shell and AMSO are the other two companies that hold oil shale leases in Colorado.
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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.
Wed Apr 27, 2011 7:12am EDT By Ari Rabinovitch
* IEI says could produce 50,000 bpd at cost of $35-$40/bbl
The company, Israel Energy Initiatives (IEI), has already invested “tens of millions of dollars” in preparing a pilot project it hopes to launch by the end of 2011, CEO Relik Shafir told Reuters.
“If successful, in a few years IEI could start producing 50,000 barrels of oil a day, or 20 percent of Israel’s consumption, for 30 years,” Shafir said.
The division of IDT that owns IEI is called Genie Energy, and it has already brought investments from financier Jacob Rothschild and media mogul Rupert Murdoch. Together they own a 5.5 percent stake worth $11 million, according to a company statement from November.
Murdoch, upon joining Genie Energy’s advisory board last year, said the group would “spur a global, geo-political paradigm shift by moving a major portion of new oil production to America, Israel and other Western-oriented democracies.”
Rothschild made similar comments.
Israel’s oil shale deposits have been known about for decades. A 2005 U.S. Geological Survey report listed Israel among 14 countries with serious oil shale potential but they only became commercially viable since the price of oil skyrocketed. U.S. crude CLc1 is currently above $110 a barrel.
Israel’s Infrastructure Ministry says subsurface oil shale covers 15 percent of the country, and the amount in the area of IEI’s license alone is comparable to the oil in Saudi Arabia.
Relik said his company could produce high-quality oil on a large scale at a cost of $35-$40 a barrel.
There is strong government support to pursue oil shale, which together with newly discovered off-shore natural gas fields, would move Israel closer to energy independence. But there are also some major obstacles.
IEI’s exploration licence covers an area near the biblical Ellah valley just outside Jerusalem where it is believed David fought Goliath. Residents and powerful environmental groups oppose even the small pilot project.
Further complicating the progress, a small oil shale mine in the southern Negev desert run by Israel Chemicals (ICL.TA) caught fire earlier this year. It took weeks to extinguish the blaze, causing environmental damage and fueling opposition. Since then, the company said it might close the mine.
IEI says it uses a much newer technology, similar to what oil giant Royal Dutch Shell (RDSa.L) uses in the western United States and is trying to introduce in neighbouring Jordan. In fact its chief scientist, Harold Vinegar, for years held the same position at Shell.
Most of the work will be done below the surface. In the pilot, IEI will drill 250-300 metres deep, inject heat, and come away with five barrels a day. It will simply be graded up for the commercial stage.
Israel’s Infrastructure Ministry told Reuters it would consider granting further licences for oil shale exploration, though other foreign firms will likely wait to see IEI’s fate.
(Editing by Jason Neely)