What’s new in exploration

	Vol. 231 No. 5
CHRISTOPHER LINER, PROFESSOR, UNIVERSITY OF HOUSTON

Exploring shale gas plays

There is no easy way to write about shale gas. It is remarkable how soon the previously unthinkable becomes routine. As recently as the late 1990s, it was commonplace during drilling to get a burp of gas while passing through shale, and ignore it. Shale was the “background rock” that held the interesting formations: conventional sandstone and carbonate reservoirs with good porosity, permeability and structural settings. Below conventional reservoirs, shale has always been important as source rock—a basic picture that has not changed.

In ancient oceans, plankton and clay settled to the seafloor and were preserved by the low-oxygen environment. Sediment piled up over geologic time, compressing, burying and heating the organic-rich mud, transforming it into black shale containing a mixture of organic material called kerogen. Further burial and heating of the shale cracked the enormous kerogen molecules to generate oil and, at higher temperature, gas. Thus, shale is the hydrocarbon kitchen generating oil and gas, then expelling it to be pooled and trapped farther up in those well-studied reservoirs. What we did not know until recently was that enough gas stayed behind to make shale itself a viable target. A century of study has been pointed at the conventional reservoir, while the idea of shale as a primary gas reservoir is barely 20 years old.

Shale is the finest-grained member of the clastic rock family that includes sandstone, siltstone and mudstone. In a sense, grain size is all that defines a shale, but our common notion also includes something about clay minerals, depositional environment (e.g., deep water) and organic content. Shale variability is bewildering, including wide ranges of porosity (3–15%), permeability (milli- to microdarcies), mineralogy (clay, silica and carbonate), total organic carbon (2–10%) and mechanical properties. A complicated picture indeed, and a case could be made that many of the famous “shales” are not shale at all—parts of the Bakken are dolomite, sandstone and siltstone; the Barnett is mostly mudstone; and the Marcellus is part siltstone with up to 60% silica content. One is reminded of the old MIT physics story about a PhD qualifying exam where the candidate was asked to define the universe and give three examples.

But shale gas plays are here to stay. The motivation is clear. Take, for example, the Barnett play in Texas, where shale gas production grew from 100 Bcf/yr in 2000 to 1,400 Bcf/yr in 2008, an annual growth rate of 34%. The play names themselves have taken on a billion-dollar buzz: Barnett, Haynesville, Utica, Woodford, Marcellus, and even the quaint Fayetteville. This is quite a shift of fortune for a shale previously famous only for a fault in the local railroad cut on Dickson Street in Fayetteville, Arkansas.

Unconventional gas resources are generally grouped into tight gas sands, coalbed methane and shale gas. Tight gas is the leader in proved reserves, but recent growth seen in US reserves has been due almost entirely to shale gas. Recent estimates for 2008 indicate that shale gas accounts for more than 30% of US gas reserves. What is it that sparked this shale gas boom, when we had been drilling right through it for decades?

Consider the most mature and best-studied shale gas play, the Barnett. From the first well in 1981, shale gas was on a slow growth curve until two key technologies combined to blow the cork out of the bottle: horizontal drilling and massive fracture jobs. All those years when shale gas was just a curious show on the way down to a conventional target, the shale was being tested by a vertical wellbore. Even the thickest gas shales have a relatively thin vertical zone with the best production. A vertical well encounters only this thin gas-rich zone, but a horizontal bore can open up several thousand feet of the good stuff. The best horizontal Barnett wells can make about three times the gas production of the best vertical wells. Since 2003, horizontal drilling has been standard procedure in every shale gas play.

Meanwhile, a change in fracturing technology around 1998 brought the cost of frac jobs down significantly and allowed operators to do bigger treatments. As with the geology of shales, frac technology is a vast field of study. The goal is to expose more reservoir rock by injecting fluid (to create fractures) and proppants (to keep them open). Big jobs in the Barnett can involve pumping 7–8 million gallons of material down the well from an armada of pump trucks. No circus coming to town can match the spectacle.

As a geophysicist, I would be remiss not to mention seismic technologies related to shale gas. As with all things shale, the literature is vast; over 400 pages of technical papers have been published by the Society of Exploration Geophysicists alone. Daunting, but I’ll mention a few highlights.

When faults are nearly vertical, the chances of cutting one in a vertical well are small. But when horizontal wells are steered laterally for several thousand feet, the chances go way up. At up to $10 million per well, an unmapped fault is not a pleasant surprise. Only seismic imaging can lead to optimized drill plans by mapping fault networks in 3D, while also indicating important natural fracture trends. Modern full-azimuth 3D seismic data can deliver a truly remarkable view of the subsurface, including very small faults, using advanced seismic attributes like curvature and coherence. Finally, I can only mention the recent, and extraordinary, progress in microseismic monitoring of frac jobs.

For now concentrated in North America, there is a mad scramble to find shale gas analogs elsewhere in the world. But, like all unconventional resource plays, shale gas is a thin-margin business, even in a hypercompetitive, high-technology, open-market situation like the US. Success elsewhere will depend on regulatory and business environments every bit as much as geology. 

ACKNOWLEDGMENTS

I would like to thank Larry Rairden of EOS Energy and Mary Edrich of Geokinetics for useful discussions and sharing of information.