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 find 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 the technology gets better producers are able to get more gas, not less.
Mark Whitley, senior vice president of Range Resources, said the new technology developments have “driven this play, but the expansion has also been driven by more geoscience.” Shale drilling is like a “gas farming operation,” he said. “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.
Determining which publicly held U.S. companies are developing shale is difficult, said Phil DeLozier, EOG Resources’ vice president for business development. “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.
“Not all acreage is created equally,” DeLozier said. But companies appear 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 5,000 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 Bleichroeder Inc. analyst John 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.
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.”
He said the Fayetteville shale “had never produced in Arkansas, but everybody knew there was gas in it.” Everything changed with the fractionation technologies developed for 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.”
©Copyright 2006Intelligence Press Inc. All rights reserved. The preceding news reportmay not be republished or redistributed, in whole or in part, in anyform, without prior written consent of Intelligence Press, Inc.
© 2020 Natural Gas Intelligence. All rights reserved.
ISSN © 1532-1231 | ISSN © 2577-9877 |