It's been more than a century since the first natural gas wells were sunk in the United States - shallow holes in the rigid shale formations of Appalachia.
As experience grows, so does the number of successful wells, which in turn increases the amount of recoverable gas.

Since then, new technologies have allowed drillers to go after deeper, more prolific gas basins from the Northern Plains to the Southwest, from the Gulf of Mexico to the Rocky Mountains - relegating shale-based gas to the status of "unconventional" if not "marginal."

Until now.

Although much of the industry's attention to future domestic supply has focused on coalbed methane and the deepwater Gulf, shale is making a huge comeback - as evidenced by the surge in activity in Texas' Barnett Shale, which has propelled Devon Energy to the Lone Star State's largest gas producer. And shale formations in other parts of the country, from Wyoming to Arkansas to Appalachia, are attracting millions of dollars of new investment.

Estimates of how much gas is sandwiched between shallow layers of prehistoric mud now as hard as a chalkboard change constantly as more exploration-and-production companies plunk their bets on those quirky, unconventional plays - and have more success coaxing commercial quantities of gas out of them.

In the 1980s, only tiny Mitchell Energy was pushing drill bits into shallow but tightly bound layers of Devonian-age "black" shale, hoping to get at the softer, gas-bearing layer of sedimentary rock, often cracking the surface with water or gelatins to open up its minute cracks and release its gas.

Now, Oklahoma City-based Devon, which bought Mitchell Energy in 2001, operates 1,700 of the more than 3,400 wells in the Barnett - wells that recently propelled Devon's gas production there past 1 Bcf/day. (podcast: major shale gas players and the obstacles they face)

The Barnett is productive enough to have stopped the decline in Texas' overall gas production with the 768 Bcf of shale gas extracted in 2007, or 6% of the state's annual gas output.

According to the Energy Information Administration (EIA), one Barnett field, Newark East, is the sixth-largest gas field in the United States.

And as prolific as it is, the Barnett is just one part of what many E&P companies see as a nationwide shale drilling boom that will produce substantial volumes of gas to help meet growing demand even as conventional production flattens or declines.

While the Barnett is one of the youngest US shale discoveries, the granddaddy is the Appalachian Basin, which runs along the western edge of the Appalachian Mountains from New York to Ohio and Kentucky.

The Energy Information Administration estimated in 2000 that 23.4 trillion cubic feet (Tcf) of recoverable gas lay beneath that field, the largest amount of any shale field except the Barnett.

EIA's estimates seem to be too low. The Marcellus Shale, the part of the Appalachian Basin that lies 6,000 feet below the Appalachian Mountains and runs diagonally southwest from Canada, through New York state and Pennsylvania to West Virginia is now estimated to hold 50 Tcf of recoverable gas in Pennsylvania alone.

With 21,000 wells, the Appalachian Basin shale produces roughly 120 Bcf/year, according to the American Association of Petroleum Geologists.

Techniques for drilling for shale gas vary from field to field, and sometimes even within the drilling boundaries of a single well pad. The right combination of drilling and fracturing varies as well, often within geologically similar formations.

As experience grows, so does the number of successful wells, which in turn increases the amount of recoverable gas.

For instance, the Barnett holds an estimated 26 Tcf of recoverable gas, according to a March 2004 report from the U.S. Geologic Survey - 10 times the amount thought recoverable just a decade earlier.

The impact of tax incentives on shale gas

In the past, advances in shale exploitation technology were financed by smaller companies taking advantage of significant state and federal tax breaks. The so-called Section 29 credits in the federal tax code spurred drilling in Michigan's Antrim Shale from 1985 to 1995, with the Gas Technology Institute doing the pioneering experiments with different methods of fracturing.

The tax credit went away, but not before 6,500 shallow Antrim wells were sunk - wells that still produce 790,000 Mcf/day, according to Western Michigan University's Michigan Basin Core Research Laboratory.

Texas still gives shale plays favored tax treatment, which, according to several industry observers, accounts for Mitchell Energy's ability to learn on the job in the Barnett. But sustained gas prices north of $6/Mcf are the real motivator, according to industry officials and analysts.

Mitchell once had the farm-to-market highways all to itself, but with 3,400 wells drilled and hundreds more to come from Devon and relative newcomers such as Chesapeake Energy, EnCana, XTO Energy and EOG Resources, the highway is getting jammed.

"The tax incentives encouraged oil and gas companies to try new things," said Devon's exploitation manager, geologist Jeff Hall. "My personal opinion is that while conventional resource plays will continue to produce, the big finds are unconventional."