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COPYRIGHT 2005 Hart Publications, Inc.
The rousing success of the Mississippian-aged Barnett Shale play in North Texas has reopened the industry's eyes to the potential locked in the organic-rich Paleozoic shales layered into other petroliferous basins.
Shale gas plays are continuous-type accumulations, covering immense areas. They are a well-known resource William Hart drilled the first shale-gas discovery in 1821 in Fredonia, New York. A pipeline made from hollowed-out logs transported gas produced from the Devonian Dunkirk Shale to the town center, where it was burned to light the main street.
Nonetheless, shale wells have traditionally been modest producers characterized by low production rates and long lives. And despite its lengthy history, shale gas has only managed to comprise a small percent of total U.S. gas production.
That's all changed in recent years. Today's improvements in horizontal drilling and fracturing technologies are delivering some sterling rates from shale wells. Operators around the continent have taken notice of the prolific production flowing from the Barnett Shale, and are exporting techniques honed in that play to new basins.
Naturally, each basin is geologically unique and requires a custom approach. Gas shales are both source and reservoir in one package, and they are far from uniform. Characteristics such as total organic contents (TOC), gas contents, thickness, depths and lithologies vary from basin to basin and also change within basins. Additionally, gas shales can contain biogenic or thermogenic methane, and their thermal maturities can fall along a broad continuum. Too, both sorbed and free gas are found in gas shales, and the shales can be overpressured or underpressured.
For the 21st-century explorer, working with gas shales means experimentation. There is little risk of not locating the resource; rather, the challenge lies in delivering high enough production rates at low enough costs to make money. Now, bountiful commodity prices offer the perfect environment to encourage widespread investigation of the many shale-gas plays in the U.S.
Fayetteville Shale
One of the most exciting plays bursting on the scene is the Fayetteville Shale of the eastern Arkoma Basin. Houston-based Southwestern Energy Co. believes that it has found a keeper in the Fayetteville, a black, organic-rich Mississippian shale that is the geological equivalent to the Barnett Shale and to the Caney Shale in Oklahoma. It occurs below the Pennsylvanian sands that are the major conventional gas reservoirs in the Arkansas Fairway of the Arkoma. (For more information on the Barnett, see "Barnett Shale," Oil and Gas Investor, April 2005.)
The firm keyed on the shale interval after it noted that some of its completions in the fairway in the Wedington sandstone, a unit embedded within the Fayetteville, 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 the merits of the shale as a stand-alone objective.
During a full year of intensive study and mapping, the firm concluded that the Fayetteville compared favorably to the Barnett and other producing shale reservoirs. The Arkansas shale looked very promising from core and log analysis: it was thermally mature and its TOC ranged from 4% to 9.5%. The gas contents were between 60 and 220 standard cubic feet per ton, and gas-in-place was initially estimated at 58- to 65 billion cubic feet (Bcf) per section.
The Fayetteville was a genuine exploratory play, however, as the prime areas of thick shale did not coincide with the developed fairway where Southwestern had its historical operating position. From a thickness of 50 feet in the fairway, the shale expands to as much as 325 feet in the counties to the east.
In early 2003, Southwestern launched a major lease acquisition program, which it carried out as close to the vest as possible. It succeeded well beyond its initial expectations: since 2003, it has amassed 630,000 net acres in the exploratory area of the play, in addition to the 125,000 net acres it already held in the fairway. On its new leasehold, its land costs averaged $50 per acre at year-end 2004, terms average more than nine years, and royalties are 12.5%.
"The part of the basin we were focusing on was a very rural area that had never had any real production, so we were able to lease without attracting wide attention," says Harold Korell, president, chairman and chief executive officer.
By mid-2004, Southwestern was ready to drill. Its first wells were in Conway County in its Griffin Mountain pilot area in 9n-17w and 9n-16w. it selected the area based on geologic parameters as...
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