Natural gas production from the Barnett Shale of Texas in the past three years has been nothing short of remarkable, but few realize that at least 84% of the entire play still remains untapped. Its full potential will rely on new technology not yet available, Devon Energy Corp. CEO J. Larry Nichols said Wednesday.

Devon, the largest leaseholder in the play, controls 733,000 acres in the Barnett, with 127,000 core acres, 540,000 noncore acres and 66,000 acres in the western part of the play. With 2,500 producing wells, the Oklahoma City-based independents net production is now 650 MMcfe/d. Of the top 50 producing wells in the Barnett, a recent study showed Devon owned 26, dwarfing all of its burgeoning competition. Devon, however, has only just begun to demonstrate its wherewithal in the vast play.

“We have clearly not begun to peak out in this field,” Nichols told financial analysts Wednesday at Lehman Brothers CEO Energy/Power Conference in New York City. Devon’s core focus is in the Fort Worth Basin, but it still holds thousands of acres that have not been explored. “No one has the technology to get it out at this time,” said Nichols of some of the noncore resources. “As we continue to do research with several universities, some cutting-edge technology over time…will unlock the mysteries of how to get more of that gas out. No one is in a better position to do this than Devon.”

Fort Worth-based XTO Energy Corp. concentrates about 85% of its resources on tight gas plays, and is second only to Devon in the Barnett play. XTO CEO Bob Simpson said Wednesday that XTO’s output in the Barnett is approaching 300 MMcfe/d, which it hopes to double in the next three to four years.

“It’s a huge field for us with tremendous upside,” said Simpson. “And only a fraction of the Barnett Shale has been booked.” Simpson’s company controls about 80,000 acres in the area, and as leases expire in the coming years, he hopes XTO can secure more acreage. Barnett, he said, is “the gold standard of shales.”

That wasn’t always the case. Just 11 years ago, the Barnett didn’t amount to much by most experts’ estimates: the U.S. Geologic Survey (USGS) assessment of significant U.S. gas fields didn’t even consider it worth mentioning in 1995. Today, however, USGS estimates that about 26.2 Tcf of gas remains to be discovered in the play; some experts put the potential at about 1 Tcf of gas per seven square miles.

Devon proved that the Barnett is a phenomenal play, but it’s difficult at this point to understand the shale’s true potential. Most of the 60-plus producers operating in the Barnett shale have only drilled within the core area in North and East Texas. The play is far reaching, however, extending from the Fort Worth Basin of North Texas into the Permian Basin of West Texas and New Mexico. Horizontal drilling has been key to unlocking the resources throughout the core regions, but as producers have extended their efforts into noncore leaseholds, they’ve found some of the shale requires different fracturing techniques. Recovery there is more frustrating upfront but ultimately well worth the effort.

With its drilling success and plenty of cash, Devon has been able to do what few independents can do: finance new technology to improve its techniques in the shale, which improve its odds for success.

“The exciting thing is, we’ve expanded into the noncore and increased our recovery rate,” Nichols said.

Devon has been the No. 1 Barnett producer since it purchased the assets of Mitchell Energy & Development Corp. in 2001 (see Daily GPI, Aug. 15, 2001). Its rapid ramp-up began three years ago, and in 2005, Devon drilled 268 wells in its core holdings. This year it plans to drill 385 wells. Devon’s “minimum expected recovery” on the acreage is 13,467 Bcfe: 3,067 Bcfe proved, 5,980 Bcfe unproven, with the additional potential of 4,600 Bcfe.

Nichols noted that Devon’s estimates on the potential shale gas output continue to increase. In 2002, Devon estimated its ultimate recovery from the Barnett was 9-10%, putting the remaining resource in place at around 91%. By 2004, the producer had upped the ultimate recovery to 10-12%, with the remaining resource in place estimated at 89%. This year, Devon estimated its ultimate recovery was 16%, with 84% of the resources remaining. It has grown its production from 250 MMcfe/d in 2002 to a current level of 650 MMcfe/d, and “we have publicly stated we intend to take our own net production up to 1 Bcf/d by 2009,” said Nichols.

Both independents and major producers have taken notice. In 2005, more than 6,200 permits were issued by Texas regulators to drill across 18 Barnett shale-laden counties, with more than 1,000 of the permits issued for noncore areas. Industry operators obtained about 1,250 permits last year for horizontal wells, with about a third of those in the noncore area of the play.

Mitchell unlocked the Barnett potential with its first well completion in 1981, and it led the way in horizontal drilling techniques. Today, producers are unlocking the gas in thinner, shallower gas-mature regions using advanced 3-D seismic, micro-seismic, fracture mapping, horizontal drilling and completion techniques. The only thing holding back even more expansion is additional state-of-the-art technology, said Nichols.

One of Devon’s operational objectives going forward is to concentrate more effort in the noncore regions where production has been stymied by the layers of limestone that separate the gas deposits from the nearby water-logged formations. The Mississippian-age Barnett Shale is tight, and its drainage area is limited.

Even a minor reorientation of fracturing in the Barnett has “essentially opened up a new reservoir to production,” according to the Petroleum Technology Transfer Council of Texas. “It is similar to getting a whole new well at times. Currently, most well workovers involve refracing the Lower Barnett with better frac technology and adding Upper Barnett perforations. About two-thirds of the production increase and reserves observed in refrac treatment completions come from the Lower Barnett. Although the first series of refracs have proven profitable, none of the wells are mature enough to test the potential of additional rounds of refracing.”

The challenge, said Nichols, will be to figure out what works to get more gas from the original gas in place.

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