With production from conventional gas fields declining across North America, gas shales are poised to increase their contribution to the nation’s gas supply. There are approximately 40,000 producing wells and fewer than two-dozen significant gas shale plays in the United States today, but the one that could potentially provide the biggest payoff –the Conasauga play — is still a largely unknown quantity.
Experts say gas shale accounts for about 8% of U.S. production, but that number is expected to grow to double digits in the next few years (see Daily GPI, June 4). Officials from Dominion have hinted that the Conasauga gas shale field, encompassing a huge swath of acreage extending through central Alabama and Georgia, may eventually become a major producer. But they caution that Conasauga is in the “early stage of development,” with only small amounts of gas produced so far. Some of those having the best handle on the area’s productive capacity aren’t sharing specifics, but there’s no hiding the increased presence and stepped up activity of the natural gas industry in the area.
Energy companies and investors have been buying drilling rights in the area at a fever pitch. Last year Oklahoma City-based Chesapeake spent $75 million to buy half of Energen Corp’s interest in 200,000 acres of the Conasauga field and committed another $30 million to drill in the area.
The buzz started a year earlier when Dominion Exploration & Production, a subsidiary of Dominion, bought out a smaller energy company that had been buying mineral leases in St. Claire County. Within just a few months Dominion was reporting positive results. In May 2005 one well near Ashville, AL, “encountered a significant gas flow at roughly 3,500 feet,” according to the testimony of one Dominion official during a recent hearing of the Alabama State Oil & Gas Board (ASOGB). The specific gas flow was not recorded because “the gas encountered presented a significant danger to the drilling rig,” which initiated control procedures and shut the well in. In December, 2006, another Dominion well in St. Claire County tested at a rate of 26 Mcf/d. The ASOGB reported that six wells produced a total of 2,669 Mcf in April, with each well producing from one to 10 days during the month. The most productive well produced 1,007 Mcf in seven days.
Newspapers in Alabama have reported that Dominion has paid area farmers $500 per acre signing bonuses to lease their land, plus 18% shares of any gas royalties. By May, Dominion, more than two years years into its Conasauga exploration, had 13 wells in some stage of development and had spent a reported $50 million on the project. Earlier this month Dominion, looking to consolidate its operations, shed most of its onshore exploration and production operations in a $6.5 billion, two-way deal that sent its Conasauga interests to Loews Corp. (see Daily GPI, June 11). A Loews spokesperson told NGI it would be “premature” to discuss the company’s plans for Conasauga before the sale closes, probably some time in August.
The Alabama drilling operations face problems engineers working in the Barnett shale in Texas, currently the top shale producer in the nation, have not encountered. Rock units in the Conasauga area are highly folded and faulted, making geologic interpretations difficult. Thrust faults — low angle reverse faults — are the principal faulting mechanism in the area. The Conasauga Shale can be several thousand feet thick as a result of stacking of faulted strata.
At the ASOGB hearing Dominion officials reported that the wells the company was drilling, in then-required 40-acre spacing, encountered steeply tilted rock layers, which caused each of the wells to drift, resulting in the bottom location of the wells ending up some distance from the surface location. The drift problem had forced Dominion to prematurely cease drilling before reaching the desired depths. Dominion requested that the ASOGB establish a 320-acre spacing pattern for Conasauga, to help them drill deeper without having the well bottom go outside the boundaries of the well unit. The ASOGB granted the request and named the St. Claire County portion of the Conasauga the Big Canoe Creek Field, after a stream that runs through the area. It was the first shale gas field to be established in Alabama. Permanent production units were not established, due to insufficient technical data.
Dave Bolin, deputy director of the ASOGB, told NGI that while the St. Claire County wells may be promising, they have yet to produce any real revenue. Permits have been issued for 15-17 wells, and about 10 wells are tested or producing. But, while the state places both a 2% production tax and a 4-6% privilege tax on producing wells, so far it is not gathering any sizeable tax revenue from them.
“At the lower rate these wells are producing, they would be considered stripper wells and taxed at our lower rate, a total of 6%,” Bolin said. All production royalties are being placed in escrow and will not be distributed until production units come on line, Bolin said.
It’s a beginning, but the experts point out that the Barnett Shale took 20 years to develop. The Barnett, a 6,000-square-mile reservoir stretching across 15 North Texas counties, currently produces 2 Bcf/d, and some developers are forecasting that production could rise to as much as 6 Bcf/d. The U.S. Geological Survey has estimated that the entire Barnett Shale field contains 27 Tcf.
NGI‘s quarterly ranking of the top North American gas marketers (see Daily GPI, June 21) found total physical gas sales grew 4% during 1Q2007 to 123.42 Bcf/d from 118.16 Bcf/d during 1Q2006. The continued addition of some of the larger unconventional gas producers included in the survey — including several companies with large operations in the Barnett Shale field in Texas — may be a sign that U.S. gas shale basins are coming of age.
Conasauga first made news 20 years ago when Amoco Oil drew gas from a well drilled nearly two miles into the rural turf of St. Claire County, AL. At that time Amoco estimated the Conasauga Shale field at 40 square miles and as much as 10,000 feet deep — larger than the Barnett. Despite some initial success Amoco closed the well, citing falling gas prices and the potential cost of the project. Technological advances, which make it easier to drill in shale fields, and the rising cost for energy — gas is selling for three times the price Amoco would have received in the mid-1980s — have investors reconsidering Conasauga.
©Copyright 2007Intelligence 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 |