Unconventional gas resources fill the gap in future supplies: in North America, there should be enough gas to go around for years to come, but it will increasingly be from low-permeability, low-flowrate unconventional gas deposits. With a little technological boost, this may be the lower-risk path

World Oil, August, 2004 by Perry A. Fischer

It was just 1998 when US wellhead gas prices averaged $1.96/Mcf. Those days are long gone. Nobody thinks of $2 gas anymore. Going forward over the next 15 years, the lowest estimates by industry pundits are well over $3, while the high end is about $6. Will industry be able to meet the demand? The answer is a resounding "yes," but only a sustained, robust effort will keep North America supplied with gas.

The above scenario is the convention al wisdom. The only caveats to bear in mind are that virtually everyone subscribes to it--and historically, markets usually prove everyone wrong. Also, these are the same experts that told us in 1998 that US gas demand would be soaring by now and that wellhead prices would rise to $2.81 by 2020. Those earlier forecasts were profoundly wrong, calling for some 2.4 Tcf, or 12.6% more demand than is currently the case. The once-ballyhooed 30 Tcf US demand by 2015-2020 is not to be. The simple explanation is that consistently high prices--double to triple those of just a few years ago--have lowered demand.

Nevertheless, "tight" is the operative word, not only for describing the present supply and demand situation, but for the subsurface geology as well. There are rumblings that the problem is a lack of resource, but government and private estimates say the resource exists. However, excluding arctic regions, most of the resource exists in the form of unconventional gas deposits.

OVERVIEW

Unlike conventional reservoirs, which are discrete accumulations that often produce at high rates, these unconventional, or continuous, gas deposits produce at much lower rates and include low-permeability sands, fractured shales, coalbed methane, and possibly, someday, methane hydrate.

Unconventional gas resources, which do not have obvious sealing and trapping mechanisms, are typically not driven by water. These gas resources are estimated at more than 350 Tcf. (1) Some 169 Tcf are in the Rocky Mountain region, which now account for about 25% of all US gas production. (2,3) They have a high probability of geologic success and are sensitive to pricing and technology changes, as well as government incentives. In Canada, these resources are only at the beginning stages of development, and are estimated between 290 and 1,800 Tcf. (3)

Of the total unconventional gas resource base, tight gas sands have the largest proven potential. According to a recent study by the Gas Technology Institute, (1) tight gas sands in the US comprise 69% of gas production from all unconventional gas resources and account for 19% of the total gas production from combined conventional and unconventional sources. The same study (1) estimates tight gas sand economically recoverable reserves to be 185 Tcf.

TIGHT GAS SANDS

These continuous sand formations are common, and progress in a seamless way from appearing conventional--when operators have been fortunate to intersect a dense natural fracture network--to extremely tight, with permeabilities in the microdarcyrange. Generally speaking, their economic development depends on technology advances in: determining precise well placement; advances in fracturing, fracture fluids and proppants; multi-zone completions; and much denser well spacings, in some cases down to 10 acres.

Some fields, previously thought of as conventional, are now recognized as part of a continuous trend. Identification of fracture densities within these trends, together with their orientation and the ability of the drilling team to plot a wellpath that intersects as much of these as possible, will help determine production. Finding the right drill site involves identification of fracture-induced anisotropy in these tight gas sands. Multiple-azimuth 3D seismic attributes and petrophysical data analysis, together with integration of production and other data, resulted in a successful well for Burlington in a recent DOE-funded project, Fig. 1.

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In situ resource estimates in the US range from 10,000 to 20,000 Tcf and even higher, but economic development of these reservoirs is challenging, since such low permeabilities do not favor gas flow toward wellbores. There are about 40,000 wells producing gas from tight sands, with production per well averaging 170 Mcfgd. A small percentage is economically viable with present technology, particularly well stimulation, but that is likely to improve.

SHALE GAS

Since the 1920s, the Devonian shales of the Appalachian basin have produced most of the shale gas in the US, with over 21,000 wells. And this continues today. However, new plays in the Fort Worth and San Juan basins have become significant new gas sources in the last few years. These areas, together with contributions from Michigan and Illinois basins, have allowed more than 37,000 shale-gas wells to account for 3-4% of US gas production--a percentage that is expected to increase. In Canada, a 2002 Gas Technology Institute report concluded that the Western Canada Sedimentary basin held 86 Tcf of shale gas in place, but recoverability has not been established.