Barnett Just Part of Boom

By Jim Fuquay, Fort Worth Star-Telegram, Texas

Feb. 24–Lease rates going through the roof, landowners scrambling to check mineral rights, country roads full of huge trucks. The shale is all the buzz.

Welcome to Faulkner County, Arkansas.

“It really kicked in in earnest in 2006,” Faulkner County Judge Preston Scroggin said.

“Nobody ever gave a thought to mineral rights before. Ma and Pa Kettle lived here 50 years, and now all of a sudden a landman comes to the door and leases their land,” Scroggin said of Faulkner County, home to about 106,000 Arkansans.

Mention the word shale, and most people in and around Tarrant County would assume you mean Barnett Shale.

But folks in Conway, Ark., the seat of Faulkner County, would think you mean the Fayetteville Shale.

Up in Oklahoma, the first name that comes to mind is the Woodford Shale, while in Mississippi and Alabama it is the Neal or the Floyd shales. Head up the Appalachians into Pennsylvania, and it is Marcellus, or maybe Huron.

Out in West Texas, you’d hear about the Barnett again. Or the Woodford.

From virtually no production a decade ago, shales containing natural gas have become a significant part of the nation’s production.

“These are not new discoveries. They were known formations but without production,” said Bob Esser, director of global oil and gas resources at Cambridge Energy Research Associates. “Higher prices and new technology made them economic.”

Shale exploitation

In 2000, there was only one shale gas field of consequence in the United States — the Antrim in northern Michigan.

All together, shale gas accounted for perhaps 1 billion cubic feet a day, Esser said. By 2007, he estimates, production from gas shales had risen to 3.6 billion cubic feet a day, led by the Barnett Shale’s approximately 2.4 billion per day.

By 2017, Esser said, shale gas production should more than double to 7.5 billion cubic feet a day and become more than 14 percent of U.S. production. He expects the Barnett to remain the clear leader during that time.

“The Fayetteville and the Woodford are nice plays, but they’re not the Barnett,” Esser said.

“All these shales share rapidly accelerating production, at least up to about 2012,” he said, at which time he expects a leveling out as producers maximize output by improving production techniques and drilling wells as densely as is economic.

One reason production is rising so quickly in these formations, which had been considered unproductive in the past, owes to the Barnett Shale. The knowledge and experience gleaned by geologists and drillers in the Barnett is being applied elsewhere.

“The Barnett Shale took 15 years to really figure out. The Fayetteville took four or five,” said Rodney Waller, senior vice president at Fort Worth-based Range Resources.

But that only goes so far.

“It’s fair to say that not all shales are created equal,” said Brad Foster, who oversees Devon Energy’s central U.S. operations. Devon is the largest producer in the Barnett Shale and is also working the Woodford.

“There are similarities. But everything we’re learning in the Barnett is not directly applicable to the Woodford, say,” where Devon has more than 100,000 acres under lease.

Waller described it like this: “You’ve got about 10 fundamentals in each shale. Six of those are pretty easy. What works in the Barnett Shale works elsewhere,” he said. “But the next four are really tough, and you don’t have a clue what the answer is. You have to figure out what those pieces are.”

Hard rock

The big difference, producers say, is how brittle the Barnett is.

All shales are predominantly clay, but the Barnett has a relatively high quartz content. When it is fractured by pumping millions of gallons of water and sand down a well, it cracks like safety glass, in a dense spider web of fractures, Waller said.

Other shales have more clay, which makes them more pliable, more “plastic,” in the parlance of the geologist. They tend to crack along fewer fractures, meaning not as much of the relatively impermeable rock is exposed to fractures, which let gas flow toward the well bore.

That demands experimentation to find the right combination of techniques to unlock the gas. For example, consider Range’s experience in the Marcellus of Pennsylvania and Virginia.

“We drilled our first well in the Marcellus in 2004. It was encouraging, but not a barnburner,” Waller said. But last year, he said, Range started drilling horizontal wells using different methods, and the results improved, with production of 1.4 million to 4 million cubic feet of gas a day.

“Two million a day is fabulous in the Marcellus,” he said.

Even the Barnett Shale is different in West Texas than it is in North Texas.

“The industry has probably spent $1 billion there, with not a lot to show for it,” Waller said.

Quicksilver Resources of Fort Worth has drilled six wells, both vertical and horizontal, in the Barnett in West Texas’ Delaware Basin.

“We’re encouraged by the fact we find gas in each one,” said Quicksilver’s Rick Buterbaugh.

But getting it out is another matter. “It’s going to require different fracturing techniques. It’s not as brittle as the Barnett in the Fort Worth Basin.”

Even though it looks like the Bar- nett might prove to be the granddaddy of U.S. shales, that’s not to say the others can’t be handsomely profitable for producers. Costs for acquiring leases make the other fields look downright affordable.

Rural boom times

For years, leases in Denton and Tarrant counties came with bonuses of a few hundred dollars an acre or less. Then a year ago, those bonuses exploded, approaching $20,000 an acre in some areas. Royalties as low as Texas’ state minimum, 12.5 percent of production, are routinely double that and occasionally even higher.

In Arkansas, Conway County Judge Jimmy Hart said the cost of acreage has risen but nowhere near the Barnett numbers.

“Early on, a year or two before the drilling started” in 2004, “a lot of leasing started at $25 an acre and a one-eighth [12.5 percent] royalty,” said Hart, who noted that the county is by any measure rural, with just over 20,000 people. “I’m now hearing over $1,000 an acre and 20 percent royalty.”

Scroggin, in neighboring Faulkner County, which is more populous, said he’s heard of bonuses close to $3,000 an acre, with royalties running between 16 percent and 20 percent.

And in the case of the Appalachian shales, it’s a matter of location, loca- tion, location. The area has a history of gas production and is near the populous Northeast, a big market for natural gas.

“You’ve got lots of pipelines and about 55 percent of the U.S. population, so there’s a premium on the price you can get” for gas from the Marcellus, Waller said.

If there are unknowns in how to best develop U.S. gas shales, there even bigger unknowns in just how much gas might be down there. Estimates of reserves can vary widely because their development is so new that boundaries are still being drawn.

In 2006 in the Barnett Shale, for example, the U.S. Geological Survey estima- ted gas reserves at 3.4 trillion cubic feet. Eight years later, the agency revised that by nearly eightfold, raising the estimate to 26.2 trillion cubic feet. More recent estimates are above 30 trillion cubic feet.

In the Marcellus and other Appalachian shales, the USGS estimated 31 trillion cubic feet. But researchers at Penn State University came up with 50 trillion cubic feet.

—–

To see more of the Fort Worth Star-Telegram, or to subscribe to the newspaper, go to http://www.dfw.com.

Copyright (c) 2008, Fort Worth Star-Telegram, Texas

Distributed by McClatchy-Tribune Information Services.

For reprints, email tmsreprints@permissionsgroup.com, call 800-374-7985 or 847-635-6550, send a fax to 847-635-6968, or write to The Permissions Group Inc., 1247 Milwaukee Ave., Suite 303, Glenview, IL 60025, USA.

NYSE:DVN, NYSE:KWK,