The rousing success of the Barnett Shale play in North Texas has many companies looking for similar-style plays in their own backyards.

Houston-based Southwestern Energy Co. believes that it might have found a look-alike in the Fayetteville Shale in its historical operating area on the Arkansas side of the Arkoma Basin. This summer, the company unveiled its Desoto project in the shale.

The Fayetteville, found at depths from 1,500 to 6,500 feet, is a black, organic-rich Mississippian-aged shale that is geologically equivalent to Oklahoma's Caney Shale and North Texas' Barnett. The firm keyed on the shale interval after it noticed that completions in the overlying Wedington Sandstone sometimes produced greater volumes of gas than would be expected from its reservoir properties. The likely source of the pumped-up production was pinpointed as the Fayetteville Shale, and Southwestern began to consider it as a stand-alone objective.

During a couple years of intensive geological study, the company concluded that the Fayetteville compared favorably to the Barnett and other producing shale reservoirs. The Arkansas rocks have total organic contents ranging from 4% to 9.5%; thermal maturity values from 1.5 to 4 Ro (vitrinite reflectance); and gas contents between 60 and 220 standard cubic feet per ton. The Fayetteville does not achieve the thickness of the Barnett, although it is generally shallower and may be less expensive to develop. The North Texas shale is generally 200 to 500 feet thick, while the Fayetteville ranges from 50 to 325 feet.

"We've recently begun to test our concept, and our results to date are encouraging," said Harold Korell, chairman, president and chief executive in a recent teleconference.

As of late September, Southwestern bumped its planned 2004 investment to $28.2 million in the Fayetteville, from $19.5 million. Since 2003, it has accumulated 500,000 net undeveloped acres in the promising play, in addition to the 125,000 net developed acres that it controls in the conventional fairway area. On average, its land costs are $40 per acre, its lease term is more than nine years, and its royalties are 12.5%.

The company expects to drill 23 Fayetteville wells by year-end. To date, it has drilled tests in four pilot areas in Franklin, Conway, Faulkner and Van Buren counties, Arkansas. Its first wells cost between $500,000 and $700,000 apiece, including testing, coring and special logging expenses.

The Conway, Faulkner and Van Buren counties wells represent significant leaps from established production. Southwestern began its completion attempts in the pilot wells using nitrogen foam fracs, and the wells completed with nitrogen treatments have initially produced between 150,000 and 700,000 cubic feet of dry gas per day. It uses a consistent completion technique, to better isolate the factors affecting well performance. The company is also testing the efficacy of larger volume slick-water fracs, the type of treatment commonly used in the Barnett Shale. In addition, it plans to attempt horizontal wells, another technique that has been very successful in the Barnett.

The Fayetteville is already producing 125,000 to 160,000 cubic feet of gas per day in two wells in the fairway, where the shale section is relatively thin, the company says. And, Southwestern has begun selling gas from Fayetteville wells in the undeveloped area east of the fairway, at rates of 250,000 to 450,000 cubic feet per day.

"While we are encouraged by the results to date, we recognize that the results are still preliminary and that we have a significant amount of data yet to collect in order to confirm the extent and the economic viability of the...play," said Richard Lane, executive vice president, exploration and production.

In October, Southwestern received new field rules from the Arkansas Oil & Gas Commission for its Conway County discovery, Griffin Mountain Field. The initial test in the five-well field was the #1-9 Thomas, a 3,610-foot well completed with an initial flowing potential of 532,000 cubic feet of gas per day from eight fracture-stimulated zones in the Fayetteville between 2,750 and 3,036 feet, reported IHS Energy.

In its application, the company said a vertical well would likely drain an area of 30 acres or less; estimated gas-in-place was 58- to 65 billion cubic feet per square mile; and estimated ultimate recovery is 580- to 600 million cubic feet per well.

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