The Barnett Shale of North Texas is certainly the most talked about natural gas play in the Lower 48. But similar gas shale deposits exist in more than half of the country, and private and public producers are quietly buying acreage in West Texas, Alabama's Black Warrior basin, the Arkoma basin of Oklahoma and Arkansas, Michigan's Antrim region, the Appalachian mountains and across Wyoming and Colorado in a quest to the "next" Barnett.
The reasons are obvious: the Gas Technology Institute estimates organic gas shale reservoirs in the United States contain up to 780 Tcf, but others put reserves north of 1,000 Tcf. It's not a certainty because as technology gets better, producers are able to get more gas, not less.
The idea of finding more gas has not been lost on independents or majors. Last November, analyst Natexis Bleichroeder tracked 23 producers working in shale development across the United States. "We now tally 39, and we're sure we are missing some due to the sheer magnitude of activity and companies holding leases in third-party names to maintain secrecy," said analyst John White.
"There is only one Barnett, but there are others with the same kind of potential," said Mark Whitley, senior vice president of Range Resources. "We just have to find the keys." Whitley said "technology has driven this play, but the expansion has also been driven by more geoscience." Shale drilling is like a "gas farming operation," and it "still takes experimentation to get it right...It takes fine tuning."
Gas shale exists in more than half of the country, but producers currently are focused on a few key regions: the Barnett, Fayetteville, the New Albany play in Illinois/Indiana/Kentucky, Michigan's Antrim and the Texas/Oklahoma Woodford play. They also are quietly buying acreage in emerging plays in the Black Warrior Basin of Alabama, the Mowry region of the Green River Basin of Wyoming.
In those areas, the "average working interest runs higher, and producers are blocking out bigger positions," said EOG's DeLozier. "There's a lot of M&A activity." Determining which publicly held U.S. companies are developing shale is difficult, he said. "Our best guess is around 40. Six months ago, it was about half that size. What is remarkable is the growth of this...the Barnett shale whetted the appetite for these types of plays. Developing any of these gas shale plays is a process that requires many wells and a number of years to complete," said DeLozier.
"Not all acreage is created equally," he said. "It's amazing the number of people that have the 'next best' gas shale play." But he said companies have to understand the importance of "early mover advantage. There's a lot of competition and it's important to put acreage together in the key plays." Also "size matters on most of the plays."
Shale gas plays require "continuous technical feedback," said DeLozier. "You might be shocked by the cost of trial and error. We are in fully in some of these plays, and every well is different. We learn something every time we drill a well."
Producers operating in the Barnett have shared their drilling knowledge with the rest of the energy industry, and as long as that happens, shale exploration will continue to grow. "We thought we knew everything," said Whitley. "But we don't know everything about shale...and the upside is huge."
Unlocking the shale potential is different for every play -- and in many cases, every well.
"I like to call them technical plays because it was technology, horizontal and fracturing, that brought them about," said Mike Party, a geoscientist with Wagner & Brown. "What we were doing 50 years ago couldn't tap those resources, but with technology today, we can." Each shale play is unique, "though some seem to be cousins. Some of the normal parameters for normal plays don't come into play here."
Costs also vary, according to Doug Walser of Pinnacle Technologies. Production rates could be the same, but a well that might cost around $2 million to drill in the Barnett could cost $4-$5 million in West Texas, where wells are produced at deeper depths and require more pressure to break the formation rock.
"The average depth [in West Texas] will be from a minimum of 9,000 feet to a maximum of about 13,000 feet," Walser said. In the Barnett, depths average between 5000 to 7,800 feet.
Another challenge is the lack of infrastructure. It took time for Barnett to actually ramp up because of a lack of gas pipelines and oilfield services. Now, as producers eye other shale formations, they also must question how they will get the gas out if they find it.
James McBride, managing director of structured oil and gas finance at The Royal Bank of Scotland, said what he finds "very appealing" about gas shale drilling is the "repeatability of drilling in the plays," whether it's the Fayetteville shale in the Arkoma basin or the Antrim shale in Michigan. "The improvement in technology has shown that these reserves get larger instead of smaller."
The "big believers" in shale plays understand that "scale is important," said McBride. And for producers wanting to move into some of the more promising plays, "it truly is a borrower's market. There is money out there."
Natexis analyst White said gas shale is particularly attractive for both private and publicly held companies because the technology used is transferable. Everyone looked to the successful Barnett drilling experience as a "test" case for other shale formations across the country, he said. In plays similar to Barnett, production can still be affordable with $6 gas.
Some of the more successful -- and emerging -- shale plays are easy to track by the amount of money producers are pouring into them:
The land rush is on in the Arkoma Basin of Arkansas, where the Fayetteville shale is located. The gas play stretches from the western part of the Arkoma basin to the Mississippi River, and its shale is similar to the Barnett. About 80 wells had been drilled in the play at the end of 2005, but its potential is just beginning to show.
"The best well to date is the Stobaugh 2-1-H horizontal well, which produced 3.7 MMcf/d as a 24-hour initial production test," according to Ed Ratchford, geology supervisor for the Arkansas Geological Commission. No one has set an estimate on overall reserves. "We're still early on in the whole scheme of this thing." He estimates "probably two million acres have been leased in Arkansas in the last one and a half to two years. There's been a big land-grab in here."
Most of the exploration activity is within the eastern Arkoma Basin and the Mississippi Embayment regions of Arkansas, where the shale is thicker than in the western part of the state. Thickness varies from 50-75 feet in western Arkansas to about 300 feet in the eastern Arkoma. Thickness exceeds 1,000 feet in tin some portions of the Mississippi Embayment.
"The Fayetteville shale had never produced in Arkansas, but everybody knew there was gas in it," said Ratchford. He said everything changed with the fractionation technologies developed for the Barnett.
Southwestern Energy Co. led the way into this play, drilling its first wells there in mid-2004. In May, the Houston-based producer, which now publicly holds about 875,000 net acres in the play, said it had 101 Bcf of reserves there, or about 12% of its total proved reserves.
Chesapeake Energy, the leading MidContinent producer, had acquired about 600,000 acres in Fayetteville by 3Q2005. XTO Energy, the largest gas producer in Arkansas, is said to hold at least 100,000 acres, and smaller independents have muscled in as well, including Noble Energy, Contango Oil & Gas Co., Edge Petroleum and Maverick Oil and Gas. In a sign that even the majors see the potential, Royal Dutch Shell plc quietly signed a series of transactions in 2005 to explore 70,000 acres of the Fayetteville for an undisclosed amount. Shell is said to also be leasing at least 25,000 acres in the Barnett.
On the Oklahoma side of the Arkoma basin, Devon Energy is said to hold at least 70,000 acres. Devon already is the largest player in the Barnett.
Two emerging plays in West Texas and southeastern Oklahoma include the Caney/Woodford play and another branching off of Barnett into Woodford. These plays aren't exactly new, but producers are grabbing a lot of acreage very quickly.
Morgan Stanley, which studied Newfield Exploration's success in the Woodford play, reported that the shale "compares favorably to the Barnett Shale in terms of organic content (6% to 8% versus 4.5%), per-well production rates and reserve sizes."
Woodford could rival the Barnett, according to EOG's DeLozier. "There is a tremendous resource there. We have huge resources to work on, from a few Tcf to thousands of Tcf. We just don't know."
Or the Woodford play could "be better than the Barnett," said Ben Dell, an analyst with Sanford C. Bernstein & Co. "It's in the early days, and I don't think the investment community has really woken up to that yet."
EOG and EnCana Corp. are two of the leading leaseholders in the region. Others include Burlington Resources, which is being purchased by ConocoPhillips, Carrizo Oil & Gas, Chevron Corp., Devon, Quicksilver, Range Resources, Southwestern and, of course, Newfield.
In the Appalachian basin, the Devonian Ohio and Chagrin Shales along Lake Erie have been producing commercial gas volumes for more than 100 years, with the first well drilled in 1821. It still is said to hold more than 200 Tcf.
The shale's depths range from 2,000 feet at the Pennsylvania/Ohio border to less than 500 feet near Sandusky, OH. There are three major types of shale in the region: black bituminous, greenish-gray and siltstone, with most of the gas found in the greenish-gray and siltstone.
Range Resources holds about 100,000 acres in this play, and it has reported that the shale is similar to the Barnett in terms of thickness and total organic content. Other producers holding acreage here include Chesapeake, Dominion Resources, Penn Virginia, Range Resources and Talisman Energy, which holds about 1.2 million net undeveloped acres throughout the Appalachian basin.
The legacy New Albany play in the Illinois basin could contain as much as 86 Tcf of gas, according to the National Petroleum Council Committee on Unconventional Gas Resources. The play has been mostly drilled by private producers, but that may be changing.
New Albany has actually produced gas since the late 1850s from wells in Indiana and Kentucky from Border Shale and a 100-foot-thick pay zone. Horizontal wells cost about $750,000 to drill to a depth of 500 to 2,500 feet. Peak production is 200-300 Mcf/d. Wells decline at a rate of about 5% a year with a productive life of about 30 years.
The Antrim shale in Michigan is one of the older shale plays, and though its production is said to be declining, interest in the old rock still has appeal.
Antrim wells have usually drilled to between 400-2,000 feet. They cost less than $200,000 each, and at peak production in the 1990s, the field produced about 200 Bcf a year. A typical well produces between 400-800 MMcf.
DTE Energy has been a player here for more than 15 years, but it's also attracted interest from Dominion Resources, Quicksilver Resources, Whiting Petroleum and Cadence Resources.
An emerging play is the Mississippian Floyd shale in northwestern Alabama in the Black Warrior basin. The Floyd already had been identified as a possible source rock for oil, but it also has gas potential because of its similarities to the Barnett shale.
"This gray to black fossiliferous shale is relatively thick (500-1,500 feet), and bounded above and below by dense limestone units comparable to those necessary to contain induced fractures required to achieve Barnett Shale production," said Albert Oko of Kansas State University.
Murphy Oil drilled one of the initial test wells in 3Q2004, and in a positive sign, it is continuing to purchase leases. Other leaseholders include Carrizo Oil & Gas, Edge Petroleum and Noble Energy.
This emerging shale play is located in the Green River basins of Wyoming, spreading into Colorado and Utah. Three continuous gas assessment areas have been defined in this region from its "competent fractured beds" in the source rocks, according to the American Association of Petroleum Geologists. Total gas resources, said the AAPG, have the potential for additions to reserves over the next 30 years "at a mean of about 6.5 Tcf with a range of 3.9-10.4 Tcf."
This play "is an early stage play in the Rockies," but it holds a lot of potential, said Natexis' White.
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