Gas Shale Tapped for Big Pay

Tax Credit Ignited Development

Gas shales are currently one of the hottest plays in the United States as a result of high gas prices, the remarkable success in the Barnett Shale in the Fort Worth Basin, technological advancements in drilling and completions, and predicted near-term shortages of natural gas.

Furthermore, gas shales occur behind pipe in many developed basins where conventional production is declining, an underutilized gathering infrastructure exists and markets are accessible.

There are over 35,000 producing gas shale wells in the United States, with a current cumulative production of about 600 bcf/year. Total gas shale resources in the United States have been estimated in the range of 500-600 tcf.

Outside the United States gas shales have received little attention. Gas shales resources in Canada are estimated to be over 1,000 tcf, and many operators are assessing potential gas shales either as potential incremental production or as stand alone, Barnett-type prospects.

Gas shales are fine-grained rocks in which a significant component of gas storage is by adsorption. Gas shales are unconventional, continuous-type natural gas reservoirs (Schmoker, 1996) where accumulations are volumetrically important.

In gas shales, like coalbed methane, the shale is the source, reservoir and trap for primarily methane and minor to significant amounts of other gases, including ethane, carbon dioxide and nitrogen.

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Gas shales are currently one of the hottest plays in the United States as a result of high gas prices, the remarkable success in the Barnett Shale in the Fort Worth Basin, technological advancements in drilling and completions, and predicted near-term shortages of natural gas.

Furthermore, gas shales occur behind pipe in many developed basins where conventional production is declining, an underutilized gathering infrastructure exists and markets are accessible.

There are over 35,000 producing gas shale wells in the United States, with a current cumulative production of about 600 bcf/year. Total gas shale resources in the United States have been estimated in the range of 500-600 tcf.

Outside the United States gas shales have received little attention. Gas shales resources in Canada are estimated to be over 1,000 tcf, and many operators are assessing potential gas shales either as potential incremental production or as stand alone, Barnett-type prospects.

Gas shales are fine-grained rocks in which a significant component of gas storage is by adsorption. Gas shales are unconventional, continuous-type natural gas reservoirs (Schmoker, 1996) where accumulations are volumetrically important.

In gas shales, like coalbed methane, the shale is the source, reservoir and trap for primarily methane and minor to significant amounts of other gases, including ethane, carbon dioxide and nitrogen.

In as much as the volume of adsorbed gas is strongly correlated with surface area and the source of high surface area is in the microporous organic fraction, it follows that gas shales are organic-rich and generally fine grained. Rocks included in this definition of gas shales are organic rich, true shales, mudrocks (non-fissile rocks comprised mainly of clays), siltstone and very fine-grained sandstones.

In all producing gas shales additional gas storage capacity exists in intergranular porosity and/or fractures; some gas shales, such as the Lewis Shale in the San Juan Basin, grade into tight sands. Many gas shales have substantial gas stored in the free state, and many tight sands have gas stored in the sorbed state.

The key elements for successful development of gas shales, like coalbed methane, are the presence of adequate gas in place and either the existence of adequate permeability or a rock of suitable mechanical properties for efficient completion and fracture stimulation.

The presence of gas in place requires adequate gas generative organic matter to generate either biogenic or thermogenic gas, and to retain significant gas. The minimum amount of organic matter needed is unknown. Rocks classified as gas shales have as little as 1.5 percent total organic carbon (TOC) content to over 20 percent TOC.

Gas shales are invariably fine-grained rocks, and as such have low matrix permeability (<< 1 md). Past conventional wisdom has been that natural fracturing is essential (i.e., Antrim Shale, Michigan Basin) or, alternatively, more permeable interbeds of siltstone or sandstone are required (i.e., Lewis Shale, San Juan Basin).

Recent work on the Barnett Shale has brought the importance of pre-existing natural fractures in question; some recent studies suggest the existence of natural fractures in the Barnett impedes fracture stimulation, whereas other studies suggest that wells with high pre-existing fractures are the best producers.

Production from Devonian shales occurred as early as 1821 near Fredonia, N.Y., and by the late 1880s significant production was recorded from the eastern United States' Appalachian Devonian shales, which were exploited principally because of their proximity to a gas market.

Following a long period of limited activity and higher gas prices in the late 1970s, the introduction of the Section 29 Tax Credit in 1980 for development of unconventional resources stimulated gas shale exploration throughout the United States. Presently significant commercial gas shale production (figure 1) occurs in the Barnett Shale in the Fort Worth Basin, Lewis Shale in the San Juan Basin, Antrim Shale in the Michigan Basin, Ohio Shale (and equivalents) in the Appalachian Basin and New Albany Shale in the Illinois Basin (figure 2) and (figure 3).


By far the biggest gas shale success story is the Mississippian-aged Barnett Shale of the Fort Worth Basin. The undiscovered natural gas resources in the Barnett Shale have been estimated at 26.2 tcf (Pollastro et al. 2004), and currently there are over 3,500 producing wells. (The history of the Barnett Shale and developments to 2002 were summarized in the July 2002 EXPLORER.)

Initially developed by Mitchell Energy, the Barnett play has continued to grow outside the initial "core area" as a result of improved completion and fracturing practices, horizontal drilling and successful refracing of existing wells.

Devon, the biggest operator, has drilled over 800 wells since taking over Mitchell Energy in 2001 and now operates over 1,700 Barnett wells. In August 2004, Devon announced the drilling of its 100th horizontal hole with rates up to 4 mmcfgd.

In the last several years Devon has been joined in the Barnett play by other gas players, including Burlington, Chief Oil and Gas, EOG, Quicksilver and EnCana.

EMD members are invited to view a presentation, bibliography and Web links on gas shales in the members-only area (log in required) of the EMD Web site (emd.aapg.org).


References

Faraj, B., H. Willims, G. Addison, and B. McKinstry, 2004, Gas potential of selected shale formations in the Western Canadian Sedimentary Basin: Houston, Hart Publications, Gas TIPS, v. 10, no. 1, p. 21-25.

National Petroleum Council, 2003, Balancing natural gas policy, Volume II, Integrated report: National Petroleum Council Committee on Natural Gas.

Pollastro, R.M., R.J. Hill, T.A. Ahlbrandt, R.R. Charpentier, T.A. Cook, T.R. Klett, M.E. Henry, and C.J. Schenk, 2004, Assessment of undiscovered oil and gas resources of the Bend Arch-Fort Worth Basin Province of North-Central Texas and Southwestern Oklahoma, 2003: U.S. Geological Survey Fact Sheet 2004-3022, 2 p., available online at: http://pubs.usgs.gov/fs/2004/3022/

Schmoker, J. W., 1996, Method for assessing continous-type (unconventional) hydrocarbon accumulations, in D. L. Gautier, G. L. Dolton, K. I. Takahashi, and K. L. Varnes, eds., 1995 National assessment of United States oil and gas resources – Results, methodology, and supporting data: U.S. Geological Survey Digital Data Series DDS-30, Release 2, [CD-ROM].

Shirley, K, 2002, Barnett Shale living up to potential: AAPG Explorer, v. 23, no. 7, p. 18-19, 27.