The emergence of shale gas is clearly the most disruptive force to hit the U.S. natural gas market in the past 40 years. In less than five years, the rapid growth in shale-gas production has revolutionized expectations about what is possible in domestic gas supply.

But how disruptive will shale gas be? Will its impact be felt into the next century, or will it significantly diminish by 2050? Will its impact extend into other energy markets, such as fuels for transportation? This article addresses these questions by reviewing the role of shale gas in recent U.S. natural gas production and by examining the potential size of shale-gas recoverable resources.

The recent emergence of shale gas is, in the long view, part of the growing importance of unconventional sources of natural gas—tight sandstones and carbonates, coalbed methane and shale gas—in U.S. gas production. The recent rapid growth in shale-gas production has only intensified this trend. From 1980 to 2005, unconventional gas production increased steadily, growing at an average rate of 7% annually (essentially doubling every decade). This expansion was driven by production from tight sandstones and coalbed methane.

From 1980 to 2005, unconventional gas production doubled every decade. Since 2005, it has soared, propelled by shale gas.

Since 2005, however, shale gas has become the leading force in unconventional production. Its rise has been spectacular, from a modest 720 billion cubic feet (Bcf) in 2005 to 4.4 trillion cubic feet (Tcf) in 2010. Shale gas has propelled total unconventional gas production to 12.6 Tcf in 2010 and a likely 14.4 Tcf in 2011, an annual growth rate of more than 11% since 2005. This spectacular growth has transformed expectations about the future of U.S. natural gas production.

Since 1972, when conventional gas production in the contiguous U.S. peaked at 21.2 Tcf, it has been declining relentlessly. By 2010, conventional gas production was an estimated 7 Tcf, only one-third of its peak 38 years earlier. A level of conventional production this low was last seen in 1950.

Unconventional production grew sufficiently over the past 25 years to reverse the decline in overall production from its nadir of 15.3 Tcf in 1986. While tight-sandstone and coalbedmethane production were indispensible in reversing the decline in production, they were never large enough to push total production beyond the 18 to 19 Tcf per year plateau of 1995-2005. Transitional sources of natural gas—deep and ultradeep gas, deepwater gas, and self-sourced gas—never achieved great significance, peaking at 2.1 Tcf from 2002 to 2004. Their contribution was modest—only 11% of national production at their peak—despite their being touted for a few decades as the next great source of domestic gas production.

The rapid growth in shale-gas production is pushing total U.S. production to new heights. In 2011, dry-gas production in the contiguous U.S. reached 22.6 Tcf, equaling the record level set in 1972. In 2012, that record should easily be surpassed.

Because of shale gas, unconventional gas has become the dominant source of domestic gas supply. In 2006, unconventional gas provided a plurality of production. By 2008, this plurality had become a modest majority. By 2011, unconventional gas was providing 64% of natural gas production in the contiguous 48 states.

Disruptive effects

The rapid increase in shale-gas production created major disruptive effects throughout the natural gas market, beginning in 2008. These effects were dampened by the increase in natural gas consumption from 23.3 Tcf in 2008 to a projected 24.5 Tcf in 2011. Increased use of natural gas to generate electricity (baseload, peaking, and as a necessary backup for intermittent renewable sources such as wind) drove this consumption rise.

The most obvious disruptive effect of shale gas has been manifested in natural gas prices. During the past decade, gas prices rose steadily from their recent market low point in 2002. From 2004 to 2008, the average wellhead price was $6.68 per thousand cubic feet (Mcf). By early 2008, the industry expectation was for even higher prices, an outlook seemingly confirmed by a peak average wellhead price of $10.79 in July. But the combination of the financial crash and rapidly rising shale-gas production sent gas prices plummeting 70% to only $3.18 per Mcf by April 2009. Since then, wellhead prices have stabilized around $4.

Since late 2009, many analysts have been forecasting that wellhead prices will soon rebound from these low levels, citing the decline in gas-well drilling as the prime justification for their prediction. What they ignore are three key factors: the immense size of the shale-gas resource base, the change in composition of gas drilling (basically a near elimination of low-productivity gas wells to focus on high-productivity wells and gas wells with substantial liquids), and the efforts by major shale-gas operators to optimize drilling and completion practices, thereby reducing the marginal cost of substantial amounts of new supply. The low prices of the past three years are thus likely to persist for at least a few more. (At press time, the three-year strip on Nymex was below $4.)

If natural gas prices do rise, it will be because the increase in shale-gas production is insufficient to counterbalance the decline in other sources of domestic gas production. Exploration and development of conventional natural gas resources practically ceased in the U.S. by second-half 2009, resulting in an estimated 1 Tcf drop in conventional gas production in 2010. Preliminary data for 2010 indicate that other unconventional sources of natural gas—tight sandstones, tight carbonates, and coalbed methane—have stopped growing. Substantial undeveloped resource potential remains in these plays, but realizing that potential requires well downspacing, particularly in the major tight-sandstone gas plays that have been developed extensively over the past 10 to 15 years. Because these downspaced wells will have significantly lower reserves, they are uneconomic at current wellhead prices.

The increase in shale-gas production has had an even more disruptive effect on U.S. gas imports. Gross imports from Canada declined 18% from 3.78 Tcf in 2007 to 3.1 Tcf in 2011. Net imports from Canada (gross imports less exports, mostly re-exports, to Canada) declined nearly twice as fast, from 3.3 Tcf in 2007 to 2.2 Tcf in 2011. Imports of liquefied natural gas (LNG), which were poised to take off following billions of dollars invested in the mid-2000s in receiving and gasification facilities, instead dropped 40% to 50% from their 2007 peak.

Consumption

In sharp contrast to the considerable effects of shale-gas production on other sources of gas supply, its effects on natural gas consumption have been relatively minor. Increased production at comparatively low prices has promoted growing use of gas for electrical generation. Displacement of heating oil by gas seems to be a natural, given the geographic proximity of the immense Marcellus shale-gas resource to the major heating-oil markets and the large and likely persistent price disparity between the two fuels. But such a displacement is not yet clearly discernable.

Enthusiasm about the potential of shale gas and other unconventional gas resources has stimulated ambitious proposals to increase natural gas use in the U.S. These include a large role for natural gas (largely compressed natural gas) as a transportation fuel displacing both gasoline and diesel fuel; construction of gas-to-liquids conversion plants; and conversion of recently built LNG regasification facilities to liquefaction plants to enable LNG exports from the U.S. to Europe and East Asia.

Resource potential

The single biggest question facing U.S. energy policy today is whether such proposals are feasible or desirable. The answer depends on estimates of gas resource potential. Even a cursory examination of the gross dimensions of the challenge demonstrates the need for immense gas resources to make such proposals feasible. Meeting current levels of demand with modest increases requires production of 25 Tcf per year or 250 Tcf per decade. Forty years of consumption at this level requires 1,000 Tcf.

Conventional gas production declined by two-thirds from 1972 to 2010.

Meeting the ambitious scenarios for natural gas consumption requires 30 to 35 Tcf per year, 300 to 350 Tcf per decade, and 1,200 to 1,400 Tcf over 40 years. By comparison, cumulative U.S. gas production for more than 80 years through 2010 totaled only 1,120 Tcf.

Realizing immense resource potentials, especially for unconventional gas, typically requires megaplays. (A megaplay is defined as a play with an ultimate recovery of at least 30 Tcf, equivalent to a conventional supergiant gas field.) Historically, megaplays have been extremely rare in the U.S. Only one such conventional play exists, the supergiant Hugoton-Panhandle gas field in southwestern Kansas and the Oklahoma and Texas panhandles. (Conventional gas in the U.S. is the one known anomaly internationally to this rule. The large conventional natural gas resource of the U.S. was con- centrated in 45 major plays, those with 3 to 30 Tcf ultimate recovery each.)

The other unconventional sources are also lacking in megaplays. At best, there will be only one tight-sandstone megaplay and one to two coalbed-methane megaplays.

Fortunately, there is a strong consensus that the U.S. contains at least five shale-gas megaplays: the Marcellus (Appalachian Basin), the Haynesville/Bossier (straddling the Arkla and East Texas basins), the Fayetteville and Woodford (Arkoma Basin), the Barnett (Fort Worth Basin), and the Eagle Ford/Pearsall (the south Texas portion of the Gulf Coast Basin) all qualify as prospective megaplays.

The accompanying graphic shows the importance of these five shale-gas megaplays for U.S. gas resources. Cumulative resource assessments are shown for four different estimators. The five plays are listed in declining order of importance, beginning with the Marcellus (plus the Huron and Utica) on the left and proceeding through the Haynesville (and overlying Bossier), the two Arkoma Basin megaplays (Fayetteville and Woodford), the Barnett, and the Eagle Ford (plus the underlying Pearsall). The left vertical axis shows the estimates in hundreds of Tcf; the right axis converts these amounts to years of supply, based on 25 Tcf per year.

The four estimators are Intek (prepared for the Energy Information Administration), the Potential Gas Committee (PGC), Rystad Energy, and the U.S. Geological Survey. All (except for the Barnett estimate by the USGS) are recent estimates, published in 2010 and 2011. The PGC and USGS estimates are means of probability distributions. The Intek and Rystad Energy estimates are their published single-point estimates (which possibly are means of distributions as well). For each estimator, estimates for these five megaplays total 80% to 95% of their national estimates for shale gas.

Despite the differences in cumulative total estimates, these source agree on several substantial points. There is a strong consensus that all five plays are megaplays, with ultimate resources exceeding 30 Tcf each. There is also a strong consensus about the relative ranking of the five plays. (Only the USGS deviates from the relative ranking used, putting the Eagle Ford ahead of the Arkoma (Fayetteville/Wood-ford) and the Barnett.) Except for the Intek estimate for the Marcellus and the PGC estimates for the Haynesville and the Fayetteville/Wood-ford, the estimates of the means for each play tend to fall within the range of uncertainty.

That uncertainty is both substantial and significant. The arithmetic sums of the range of the PGC estimates span 293 to 1,295 Tcf for these five play groups. The arithmetic sums of the range of USGS estimates span 181 to 414 Tcf. These disparate projections stem from the inevitable limitations on what is known (and what currently can be known) about these shale-gas plays. Other than the Barnett, none of these plays has a meaningful number of well-production histories longer than five years.

Because of the great areal extent of these plays, information about the distribution and extent of key rock properties, and thus of likely ultimate well recoveries, is uncertain. These questions are unlikely to be resolved substantially until the latter half of this decade.

These five plays are five of the six to eight largest gas plays ever discovered in the U.S. The two largest have no historical precedent in North America. Yet, despite this top-of-the-chart performance, the five plays only add up to 11 to 24 years of current consumption of natural gas. They are not transformative, providing for a substantial broadening of natural gas use. They are only sustaining, enabling us to maintain current levels of natural gas use for a few more decades.

Five megaplays provide most of the U.S. shale-gas resource. Their various resource estimates are shown here.

Paradoxically, in the longer view, shale gas will come to be seen as a stabilizing—instead of a disruptive—force in the national gas market. For the next 15 to 25 years, shale gas will bring relative calm to a market characterized over the past 35 years by regular supply constraints and thus, a market with considerable price instability. (The principal people who will still consider this disruptive are those who invested assuming historic supply constraints would continue.)

Many, having expected shale gas to radically transform the U.S. energy situation, may find this conclusion disappointing. But, compared to the many failures during the past three decades of other highly promoted sources of new domestic energy supply, shale gas should be seen as a magnificent achievement.

Richard Nehring is founder and president of Nehring Associates, based in Colorado Springs. Since 1985, Nehring Associates has been providing the Significant Oil and Gas Fields of the United States Database to the upstream industry. Currently he is chairman of the American Association of Petroleum Geologists (AAPG) Committee on Resource Evaluation. He may be reached at RNehring@ ? nehringdatabase.com? . The views expressed here are solely those of the author and not necessarily those of AAPG.

This article follows up “The Disruptive Shales,” which appeared in the

January 2009 issue and is available at OilandGasInvestor.com? .