The Disruptive Shales

?The specter of resource depletion began to fade during the past decade; average annual reserve additions from 1998 to 2006 were some 44% higher than during 1990-98, led by unconventional sources.

?For the past 35 years, the U.S. gas industry has been haunted by the specter of resource depletion. Reserves in the Lower 48 states plummeted 47% from 289 trillion cubic feet (Tcf) in 1967 to 153 Tcf in 1993. Gas production declined 32% from its peak of 22.5 Tcf in 1973 to 15.3 Tcf in 1986.

?Production subsequently managed to increase modestly during the 1990s—but only because the reserve-to-production ratio was also plummeting from 15.7 years in 1967 to a highly uncomfortable 8.3 by 1999.

?During the past decade, the specter of resource depletion has begun to fade. After three decades of annual production exceeding annual reserve additions by an average of 4.4 Tcf per year, annual reserve additions have consistently exceeded production beginning in 1999.

?Indeed, from 1998 to 2006, average annual reserve additions were 24.5 Tcf, some 44% higher than the 17 Tcf average additions from 1990-98.

?Because reserve additions consistently exceeded annual production by an average of 5.85 Tcf per year during this eight-year period, what appeared to be an inexorable tread of declining reserves, going back more than 30 years, has been decisively reversed.

?2006 saw gas reserves in the Lower 48 reach 201 Tcf, a level last seen in 1976.

This reversal was entirely the result of the emergence of unconventional gas as the dominant source of U.S. reserve additions. From 1998-2006, reserve additions from tight sandstones, coalbed methane (CBM), shale gas and tight carbonates averaged 13 Tcf per year, a 124% increase from the 5.8 Tcf per year they contributed from 1990-98. Of the 7.5 Tcf increase in reserve additions overall, these four unconventional sources contributed 7.2 Tcf or 96% of the total.

Unconventional-gas reserve additions from 1998-2006 were dominated by additions from tight sandstones. These reserve additions averaged 7.8 Tcf per year, 60% of all unconventional-gas reserve additions.

Reserve additions from CBM plays, the second-most important unconventional source during this period, averaged 2.6 Tcf per year, another 20% of unconventional additions.

Despite the substantial recent contributions of tight-sandstone and CBM plays to domestic gas reserves, these additions have failed to make any appreciable effect on production. From 1996-2006, dry gas production in the Lower 48 actually decreased slightly from 18.4 Tcf to 18.1 Tcf (the lower production in 2006 being wholly attributable to hurricanes Katrina and Rita).

The lack of any effect on production is in part explained by the growing proportion of reserves that are classified as proved undeveloped or proved nonproducing. By definition, these reserves do not contribute to current production. The more important explanation rests on the overall size of both the tight-sandstone and CBM resource and the distribution of these resources by play.

Tight sandstone, CBM

?Unlike the tight-sands and CBM plays, the largest of which are only large major plays, five to 10 of the shale plays have the potential to be mega-plays.

Traditionally in the evaluation of oil and gas resources, the focus is on field and reservoir sizes and their distribution. Unconventional-resource plays do not lend themselves well to such an approach. They are usually continuous accumulations; thus traditional field and reservoir designations, designed for discrete accumulations, do not work when applied to resource plays.

However, resource plays can be classified by size, such as these four categories: minor, significant, major and mega.

Two complementary measures are used to classify plays by size: daily production and estimated ultimate recovery (EUR). The minimum level of production for a major play is set at approximately 1% of 1996-2006 production. The minimum level of ultimate recovery for a mega-play is set at 30 Tcf, the threshold size for a super-giant gas field.

Tight-sandstone and CBM plays have made major contributions to U.S. reserve additions. But that level of contribution is also their limitation. The largest tight-sandstone plays and the largest CBM plays are only major plays; none are mega-plays (though one CBM play, the Fruitland coals of the San Juan Basin, could ultimately become a marginally mega-play).

Even though each resource type has a substantial number of major plays (16 to 18 tight sandstone and four to six CBM), their ultimate resource is still limited to an estimated 215 to 325 Tcf for tight sandstones and 65 to 110 Tcf for CBM.

Major plays are thus essentially only sustaining plays. Their development has been essential to maintaining U.S. gas production and reserves. Given the scale of U.S. gas production, their ultimate resources are insufficient to transform U.S. gas supply.

Shale gas

Unlike tight sandstones and CBM, the third-largest component of unconventional-gas resources—shale gas—does promise to transform U.S. supply. Signs of this transformation are already present. Following a decade of essentially stable production, daily U.S. gas production leapt 13.4% in just 20 months, from 50.7 billion cubic feet (Bcf) in December 2006 to 57.5 Bcf in August 2008.

The majority of the increase came from shale plays, most notably the Barnett in the Fort Worth Basin and the Fayetteville in the eastern Arkoma Basin. If this rate of increase could be maintained, U.S. production would easily exceed its previous 1973 peak as early as 2010.

The rate of gross reserve additions also reached new heights in 2007, exceeding 44 Tcf. This level of additions, which has no historical precedent in the long history of U.S. gas exploration and development, was nearly double the 24.5-Tcf average of 1999-2006, itself the highest level of reserve additions ever achieved on a sustained basis in the U.S.

The composition of these 2007 reserve additions by source is not yet precisely determined, but from their geographic locations, it is obvious that the vast majority came from the three major unconventional sources: tight sandstones, shale gas and CBM.

Shale gas promises to transform U.S. supply because it is potentially an immense resource. Following success in the Barnett, more than 20 other shale plays have been identified in the Lower 48. They share these positive traits:

• Most are areally large, exceeding 1 million acres (and ranging upwards to 30 million acres for the Marcellus shale in the Appalachian Basin.
• Most are thick, with net thicknesses averaging 100 to 500 feet or more. Thus, many have massive reservoir volumes, exceeding a billion acre-feet. (An acre-foot is the volume of liquid or solid required to cover one acre to a depth of one foot, or 43,560 cubic feet.)
• Unlike the tight-sands and CBM plays, the largest of which are only large major plays, five to 10 of the shale plays have the potential to be mega-plays, each with an ultimate recoverable resource exceeding 30 Tcf.
• At least two of the shale plays have the potential of ultimate resources considerably above 100 Tcf. Another five could be major plays. Thus, at this very early stage of evaluation, recoverable shale-gas potential ranges from 300 to 1,200 Tcf.

Disruption ahead

The development of mega-deposits of oil and gas, such as shale gas, is almost always disruptive to oil and gas markets. Their development results in the rapid addition of large new increments to supply, more than can be readily absorbed by slow-growing demand. The principal effect of their development is thus to drive down prices.

The classic, if extreme, example of the effects of development of a mega-deposit is that of East Texas Field in 1930-33. Discovered in October 1930, it was the first super-giant oil field in North America. Its development occurred when U.S. production dominated the world oil market and when world oil demand was declining at the beginning of the Great Depression.

Within three years of its discovery, East Texas Field production rose to 15% of world oil production. This increase drove the price of oil down nearly 75% by June 1933, before production controls stabilized the market at a price 35% below the 1930 price.

Formal production controls, usually politically enforced, such as those applied to U.S. oil production until 1971 and by OPEC to the present day, are unavailable to the U.S. gas industry today. Thus the only meaningful limit on production will be set by production costs. Development of shale gas will drive the price of gas down to a level where substantial proportions of the unconventional gas resource will be uneconomic to develop.

How far will the price decline and how long will this decline persist? Future prices depend on the supply curve for all unconventional-gas resources: shale gas, tight sandstones and CBM. The supply curve is essentially constructed by estimating how much of each resource will be available at a specified cost. This curve is not fixed; it changes over time as drilling and completion technology improves and, thus, reduces costs.

The effective gas-price floor is likely to be in the range of $5 to $6 per thousand cubic feet (Mcf), corresponding to a resource cost of $3.50 to $4.25 per Mcf. At the lowest levels of shale-gas potential, such prices are likely to persist into the latter half of the next decade.

Shale-gas resources at the higher levels could well result in such real prices persisting past 2025.

New markets, lower demand?

?How extreme can be the effect of a mega-deposit? Three years after its discovery, East Texas Field production had risen to 15% of world oil production, driving down the price nearly 75% before controls stabilized the market at 35% below the 1930 price.

Proponents of expanded U.S. gas production predominantly perceive its effects as supplying new markets. The major immediate impact of expanded shale production will, however, be felt in the composition of U.S. supply, not in the size of domestic demand.

The rapid recent growth in tight-sand gas and CBM production has fully replaced the decline in conventional gas production. Rapidly growing shale-gas production is likely to displace higher-cost sources of both domestic supply and imports.

This is already showing up in imports of liquefied natural gas. Touted as a major source of future U.S. gas supplies as recently as 2007, LNG imports are well on their way to becoming an inconsequential portion of U.S. supply for the next decade.

After peaking at 3.07 Bcf a day in the second quarter of 2007, they plunged 65% to 1.07 Bcf a day in third-quarter 2008. Other markets—eastern and southern Asia and Europe, where the price of natural gas is tied more closely to the world oil price—pay substantially more for spot LNG cargoes than does the U.S. market.

With rapidly rising domestic gas production and new low domestic prices, LNG is no longer a competitively priced source of gas for the U.S. market.

The effect of shale-gas development on imports from Canada will be less dramatic, but just as inexorable. Because gas markets in Canada and the U.S. are closely intertwined, low wellhead prices in the U.S. mean even lower gas prices in western Canada. Because a large portion of Canada’s remaining gas resources are high-cost, much will be uneconomic to develop in the immediate future.

Thus, western Canadian gas production will decline and Canadian gas exports to the U.S. will decline even faster. By 2020, western Canadian gas producers could find themselves competing with Appalachian shale-gas producers for customers in Ontario and Quebec.

The other major effect of shale development on domestic gas supply is likely to be an indefinite postponement of a gas pipeline from the Arctic Slope of Alaska to the Lower 48. At low gas prices, the high cost of transporting this gas makes netbacks at the wellhead very low, and hence, highly unattractive to both Arctic Slope producers and the state of Alaska.

Although unconventional gas production, particularly shale gas, will be increasing steadily during the next decade, total domestic supply will grow more slowly as unconventional production displaces other sources of supply. Thus, a rapid expansion of demand is unlikely.

What is more likely is growth in certain demand sectors. With the development of a large shale-gas resource in the Appalachian Basin, gas is likely to displace fuel oil for residential and commercial space-heating in the northeastern U.S. Demand for gas for power generation will also increase.

Gas will fuel essential back-up capacity for intermittent renewable sources of electricity, such as solar and wind. Its low price and ready availability will also displace some development of these sources.

The development of major new markets for natural gas, such as a substantial role as a transportation fuel, does not appear to be desirable. Annual domestic gas production at 25 to 30 Tcf, an amount adequate for expanded demand sectors, still means production of a quadrillion cubic feet of gas over 35 years.

The problem is that, although current unconventional sources can likely provide this amount, what will replace them once they are depleted is unknown. The current situation thus differs markedly from the situation 30 years ago, when current unconventional sources were recognized as potential sources, even though prices and technology did not exist to permit their development.

The specter of resource depletion, though currently very faint, has not disappeared. By 2050, its presence will again be confronting the industry.

Richard Nehring has been president of Nehring Associates in Colorado Springs, Colorado, since 1983. It provides the Significant Oil and Gas Fields of the United States Database. He has been researching domestic and international oil and gas resources and supply issues for more than 35 years.