Shale “fracked” natural gas peak by 2020: Mason Inman’s “Natural gas, the fracking fallacy”

[ In 2005 the U.S. was making desperate plans to build dozens of Liquefied Natural Gas plants for importing gas. Fracked gas changed that for the past 10 years, indeed, now the U.S. is talking about exporting natural gas.  But most companies have been spending more money than they’ve made, and now in 2016 we are seeing the shale bubble burst.  Even if Wall Street had been able to continue funding drillers using middle class money placed in 401K and IRA high-yield bond and stock mutual funds, scientists at the University of Texas have estimated that the largest fracked gas plays will peak in 2020.

There is a lot of natural gas left in the world.  But much of it is stranded, requiring too many miles of pipelines to reach civilization (too expensive).

Alice Friedemann  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer]

Inman, Mason. December 3, 2014. Natural Gas: The fracking fallacy. Nature 516, 28-30


The EIA projects that production will rise by more than 50% over the next quarter of a century, and perhaps beyond, with shale formations supplying much of that increase.

But such optimism contrasts with forecasts developed by a team of specialists at the University of Texas, which is analyzing the geological conditions using data at much higher resolution than the EIA’s. The Texas team projects that gas production from four of the most productive formations will peak in the coming years and then quickly decline. If that pattern holds for other formations that the team has not yet analyzed, it could mean much less natural gas in the United States’ future.

Like all energy forecasts, the lower projections from the Texas team could turn out to be inaccurate. Technological advances in the next few decades could open up more resources at lower costs, driving US production even higher than the EIA has predicted. But it is also possible that the Texas forecasts are too high, and that gas production will fall off even faster than the team suggests.

The one certainty here is that the United States and other nations have invested relatively little in tracking and assessing their natural resources. The EIA has a total budget of US$117 million, less than the value of one day’s gas production from the country’s shale formations.

Natural gas: The fracking fallacy

The United States is banking on decades of abundant natural gas to power its economic resurgence. That may be wishful thinking.

When US President Barack Obama talks about the future, he foresees a thriving US economy fueled to a large degree by vast amounts of natural gas pouring from domestic wells. “We have a supply of natural gas that can last America nearly 100 years,” he declared in his 2012 State of the Union address.

Obama’s statement reflects an optimism that has permeated the United States. It is all thanks to fracking — or hydraulic fracturingwhich has made it possible to coax natural gas at a relatively low price out of the fine-grained rock known as shale. Around the country, terms such as ‘shale revolution’ and ‘energy abundance’ echo through corporate boardrooms.

Companies are betting big on forecasts of cheap, plentiful natural gas. Over the next 20 years, US industry and electricity producers are expected to invest hundreds of billions of dollars in new plants that rely on natural gas. And billions more dollars are pouring into the construction of export facilities that will enable the United States to ship liquefied natural gas to Europe, Asia and South America.

All of those investments are based on the expectation that US gas production will climb for decades, in line with the official forecasts by the US Energy Information Administration (EIA). As agency director Adam Sieminski put it last year: “For natural gas, the EIA has no doubt at all that production can continue to grow all the way out to 2040.”

But a careful examination of the assumptions behind such bullish forecasts suggests that they may be overly optimistic, in part because the government’s predictions rely on coarse-grained studies of major shale formations, or plays. Now, researchers are analyzing those formations in much greater detail and are issuing more-conservative forecasts. They calculate that such formations have relatively small ‘sweet spots’ where it will be profitable to extract gas.

Tad Patzek, head of the University of Texas at Austin’s department of petroleum and geosystems engineering says this is “bad news, we’re setting ourselves up for a major fiasco”.

If US natural-gas production falls, plans to export large amounts overseas could fizzle. And nations hoping to tap their own shale formations may reconsider. “If it begins to look as if it’s going to end in tears in the United States, that would certainly have an impact on the enthusiasm in different parts of the world,” says economist Paul Stevens of Chatham House, a London-based think tank.

The idea that natural gas will be abundant is a sharp turnaround from more pessimistic outlooks that prevailed until about five years ago. Throughout the 1990s, US natural-gas production had been stuck on a plateau. With gas supplying 25% of US energy, there were widespread worries that supplies would shrink and the nation would become dependent on imports. The EIA, which collects energy data and provides a long-term outlook for US energy, projected as recently as 2008 that US natural-gas production would remain fairly flat for the following couple of decades.

The shale boom caught everyone by surprise. It relied on fracking technology that had been around for decades — but when gas prices were low, the technology was considered too costly to use on shale. In the 2000s, however, prices rose high enough to for companies to afford fracking shale formations. Combined with new techniques for drilling long horizontal wells, this pushed US natural-gas production to an all-time high, allowing the nation to regain a title it had previously held for decades: the world’s top natural-gas producer.

Rich rocks

Much of the credit for that goes to the Marcellus shale formation, which stretches across West Virginia, Pennsylvania and New York. Beneath thickly forested rolling hills, companies have sunk more than 8,000 wells over several years, and are adding about 100 more every month. Each well extends down for about 2 kilometers before veering sideways and snaking for more than a kilometer through the shale. The Marcellus now supplies 385 million cubic meters of gas per day, more than enough to supply half of the gas currently burned in US power plants.

A substantial portion of the rest of the US gas supply comes from three other shale plays — the Barnett in Texas, the Fayetteville in Arkansas and the Haynesville, which straddles the Louisiana–Texas border. Together, these ‘big four’ plays boast more than 30,000 wells and are responsible for two-thirds of current US shale-gas production.

The EIA — like nearly all other forecasters — did not see the boom coming, and has consistently underestimated how much gas would come from shale. But as the boom unfolded, the agency substantially raised its long-term expectations for shale gas. In its Annual Energy Outlook 2014, the ‘reference case’ scenario — based on the expectation that natural-gas prices will gradually rise, but remain relatively low — shows US production growing until 2040, driven by large increases in shale gas.

The EIA has not published its projections for individual shale-gas plays, but has released them to Nature. In the latest reference-case forecast, production from the big four plays would continue rising quickly until 2020, then plateau for at least 20 years. Other shale-gas plays would keep the boom going until 2040.

Petroleum-industry analysts create their own shale-gas forecasts, which generally fall in the neighborhood of the EIA assessment. “EIA’s outlook is pretty close to the consensus,” says economist Guy Caruso of the Center for Strategic and International Studies in Washington DC, who is a former director of the agency. However, these consultancies rarely release the details behind their forecasts. That makes it difficult to assess and discuss their assumptions and methods, argues Ruud Weijermars, a geoscientist at Texas A&M University in College Station. Industry and consultancy studies are “entirely different from the peer-reviewed domain”, he says.

To provide rigorous and transparent forecasts of shale-gas production, a team of a dozen geoscientists, petroleum engineers and economists at the University of Texas at Austin has spent more than three years on a systematic set of studies of the major shale plays. The research was funded by a US$1.5-million grant from the Alfred P. Sloan Foundation in New York City, and has been appearing gradually in academic journals1, 2, 3, 4, 5 and conference presentations. That work is the “most authoritative” in this area so far, says Weijermars.

If natural-gas prices were to follow the scenario that the EIA used in its 2014 annual report, the Texas team forecasts that production from the big four plays would peak in 2020, and decline from then on. By 2030, these plays would be producing only about half as much as in the EIA’s reference case. Even the agency’s most conservative scenarios seem to be higher than the Texas team’s forecasts. “Obviously they do not agree very well with the EIA results,” says Patzek.

The main difference between the Texas and EIA forecasts may come down to how fine-grained each assessment is.

  • The EIA breaks up each shale play by county, calculating an average well productivity for that area. But counties often cover more than 1,000 square kilometers, large enough to hold thousands of horizontal fracked wells.
  • The Texas team, by contrast, splits each play into blocks of one square mile (2.6 square kilometers)a resolution at least 20 times finer than the EIA’s.

Resolution matters because each play has sweet spots that yield a lot of gas, and large areas where wells are less productive. Companies try to target the sweet spots first, so wells drilled in the future may be less productive than current ones. The EIA’s model so far has assumed that future wells will be at least as productive as past wells in the same county. But this approach, Patzek argues, “leads to results that are way too optimistic”.

The high resolution of the Texas studies allows their model to distinguish the sweet spots from the marginal areas. As a result, says study co-leader Scott Tinker, a geoscientist at the University of Texas at Austin, “we’ve been able to say, better than in the past, what a future well would look like”.

The Texas and EIA studies also differ in how they estimate the total number of wells that could be economically drilled in each play. The EIA does not explicitly state that number, but its analysis seems to require more wells than the Texas assessment, which excludes areas where drilling would be difficult, such as under lakes or major cities. These features of the model were chosen to “mimic reality”, Tinker says, and were based on team members’ long experience in the petroleum industry.

Alternative Futures

The lower forecasts from Texas mesh with a few independent studies that use simpler methods. Studies by the following researchers suggest that increasing production, as in the EIA’s forecasts, would require a significant and sustained increase in drilling over the next 25 years, which may not be profitable.

  1. Weijermars 6, R. 2014. US shale gas production outlook based on well roll-out rate scenarios. Applied Energy, 124, 283-297.
  2. Mark Kaiser7 of Louisiana State University in Baton Rouge
  3. retired Geological Survey of Canada geologist David Hughes8,

Some industry insiders are impressed by the Texas assessment. Richard Nehring, an oil and gas analyst at Nehring Associates in Colorado Springs, Colorado, which operates a widely used database of oil and gas fields, says the team’s approach is “how unconventional resource assessments should be done”.

Patzek acknowledges that forecasts of shale plays “are very, very difficult and uncertain”, in part because the technologies and approaches to drilling are rapidly evolving. In newer plays, companies are still working out the best spots to drill. And it is still unclear how tightly wells can be packed before they significantly interfere with each other.

Yet in a working paper9 published online on 14 October, two EIA analysts acknowledge problems with the agency’s methods so far. They argue that it would be better to draw upon high-resolution geological maps, and they point to those generated by the Texas team as an example of how such models could improve forecasts by delineating sweet spots. The paper carries a disclaimer that the authors’ views are not necessarily those of the EIA — but the agency does plan to use a new approach along these lines when it assesses the Marcellus play for its 2015 annual report. (When Nature asked the authors of that paper for an on-the-record interview, they referred questions to Staub.)

Boom or bust

Patzek argues that actual production could come out lower than the team’s forecasts. He talks about it hitting a peak in the next decade or so — and after that, “there’s going to be a pretty fast decline on the other side”, he says. “That’s when there’s going to be a rude awakening for the United States.” He expects that gas prices will rise steeply, and that the nation may end up building more gas-powered industrial plants and vehicles than it will be able to afford to run. “The bottom line is, no matter what happens and how it unfolds,” he says, “it cannot be good for the US economy.”

If forecasting is difficult for the United States, which can draw on data for tens of thousands of shale-gas wells, the uncertainty is much larger in countries with fewer wells. The EIA has commissioned estimates of world shale potential from Advanced Resources International (ARI), a consultancy in Washington DC, which concluded in 2013 that shale formations worldwide are likely to hold a total of 220 trillion cubic meters of recoverable natural gas10. At current consumption rates — with natural gas supplying one-quarter of global energy — that would provide a 65-year supply. However, the ARI report does not state a range of uncertainty on its estimates, nor how much gas might be economical to extract.

Such figures are “extremely dubious”, argues Stevens. “It’s sort of people wetting fingers and waving them in the air.” He cites ARI’s assessments of Poland, which is estimated to have the largest shale-gas resources in Europe. Between 2011 and 2013, the ARI reduced its estimate for Poland’s most promising areas by one-third, saying that some test wells had yielded less than anticipated. Meanwhile, the Polish Geological Institute did its own study11, calculating that the same regions held less than one-tenth of the gas in ARI’s initial estimate.

If gas supplies in the United States dry up faster than expected — or environmental opposition grows stronger — countries such as Poland will be less likely to have their own shale booms, say experts.

For the moment, however, optimism about shale gas reigns — especially in the United States. And that is what worries some energy experts. “There is a huge amount of uncertainty,” says Nehring. “The problem is, people say, ‘Just give me a number’. Single numbers, even if they’re wrong, are a lot more comforting.”

The EIA is underfunded

Patzek says that the EIA’s method amounts to “educated guesswork”. But he and others are reluctant to come down too hard. The EIA is doing “the best with the resources they have and the timelines they have”, says Patzek. Its 2014 budget — which covers data collection and forecasting for all types of energy — totaled just $117 million, about the cost of drilling a dozen wells in the Haynesville shale. The EIA is “good value for the money”, says Caruso. “I always felt we were underfunded. The EIA was being asked to do more and more, with less and less.”

Representatives of the EIA defend the agency’s assessments and argue that they should not be compared with the Texas studies because they use different assumptions and include many scenarios. “Both modelling efforts are valuable, and in many respects feed each other,” says John Staub, leader of the EIA’s team on oil and gas exploration and production analysis. “In fact, EIA has incorporated insights from the University of Texas team,” he says.

Access the data used in this feature at

Rebuttal of the rebuttal above article

Nature published objections to the article above in a later issue, Art Berman best rebuts the rebuttal below:

Nature Responds To EIA and BEG Denial Letters

Posted in The Petroleum Truth Report on December 19, 2014

Today, Nature responded to letters earlier this week from the EIA (Energy Information Administration) and BEG (Bureau of Economic Geology, University of Texas at Austin) claiming that Mason Inman’s article “The Fracking Fallacy” published on December 4, 2014 was flawed.
Nature stands by Inman’s article and, interestingly, revealed that EIA was asked some questions by Inman while he was working on the article but they did not reply.
It is also interesting that the EIA denial letter was not signed by the EIA Administrator Adam Sieminski but by Deputy Administrator Howard Gruenspecht.
Let’s get a few things straight as people attempt to sort through this bit of energy theater.
First, Allen Brooks has documented the events and facts of this story in two issues of Musings From The Oil Patch:
Allen showed many of BEG Director Scott Tinker’s slides that set off the debate in the first of these articles but the key chart in my view is the following:

Despite denial of any differences by both the EIA and BEG, the obvious truth is that the BEG Sloan studies of the major shale gas plays in the United States forecast lower EUR (estimated ultimate recovery), a shorter life-cycle, an earlier and steeper decline and a lower contribution to total gas supply than does the EIA.
Denying that there is any discrepancy between EIA and BEG is false.  This difference does not disappear by accusing Inman and Nature of misrepresentation and bias.  Attempts by both agencies to discredit Tad Patzek or minimize his role in the BEG studies–more about that a bit later in my comments–are factually incorrect and shameful.
The BEG studies confirm what many “shale gas skeptics” (including me) have said for many years:  The shale gas phenomenon is real, it has contributed a significant volume of gas that nobody thought was available, and there is a lot less of it than some people believe.  I add that it also costs more than represented to produce although that is not part of the immediate debate among EIA, BEG and Nature.
The EIA published 2013 proven reserves of shale gas earlier this month.  Shale gas will provide about 6 years of supply at present consumption.  We can debate about the various classes of reserves and speculate about resources from now until we run out of gas but the plain and simple truth is what Inman and the BEG studies concluded:  there is less gas than many people thought and certainly less than EIA has represented in its natural gas forecasts (do the EIA people who do the gas forecasts talk to the people who do the reserve accounting?).

Much of the EIA’s position stated in Gruenspecht’s letter (and interpreted by me)  is that uncertainty exists and the EIA represents multiple scenarios and should not be held to account for one or, in fact, any of them.  That sounds good but, as someone pointed out to me, applications for LNG export to the Department of Energy are based on the EIA base case.

Tad Patzek was quoted often in the Nature article and was shamelessly “thrown under the bus” by the EIA and BEG in both denial letters.

Tad is Professor and Chairman of the Petroleum Eng. & Geosystems Department at the University of Texas at Austin and a lead researcher in the BEG Sloan studies on U.S. shale gas plays.

Despite comments in both letters saying that Tad’s role was relatively minor in those studies, I dispute those statements as distortions of fact.  The work done by Tad and his engineering team addressed the determination of individual well EUR which, in my view, is the core of the studies.

I believe that the BEG Sloan studies represent a monumental achievement and demonstrate an unparalleled level of comprehensive and integrated analysis on the important subject of shale gas. I fully support the technical analysis and Tad Patzek and his team provided the credible core of that work.  Please see the papers following for proof of this:

1.     Patzek, T.W. Male, F., and Marder, M.,“A simple model of gas production from hydrofractured horizontal wells in shales,” AAPG Bulletin, v. 98, no. 12 (December 2014), pp. 2507–2529.
2.     Patzek, T. W., Male, F. and Marder, M. “Gas production in the Barnett Shale obeys a simple scaling theory,”  PNAS, doi:10.1073/pnas.1313380110, November 18, 2013. Awarded with the Cozzarelli Prize by the National Academy of Sciences for the best paper in engineering in 2013.
3.      Patzek, T. W., Male, F. and Marder, M. “Supporting Materials to: Gas production in the Barnett Shale obeys a simple scaling theory,”  PNAS, doi:10.1073/pnas.1313380110, November 18, 2013.
4.     John Browning, Katie Smye, Scott W. Tinker, Susan Horvath, Svetlana Ikonnikova, Tad Patzek Gürcan Gülen, , Frank Male, Eric Potter, Forrest Roberts , and Qilong Fu, “Study develops Fayetteville shale reserves, production forecast, OGJ, 01/06/2014.
5.     John Browning, Scott W. Tinker, Svetlana Ikonnikova, Gürcan Gülen, Eric Potter, Qilong Fu, Susan Horvath, Tad Patzek, Frank Male, William Fisher, Forrest Roberts and Ken Medlock, III, “BARNETT SHALE MODEL-2 (Conclusion): Barnett study determines full-field reserves, production forecast,” OGJ, September 9, 2013.
6.     John Browning, Scott W. Tinker, Svetlana Ikonnikova, Gürcan Gülen, Eric Potter, Qilong Fu, Susan Horvath, Tad Patzek, Frank Male, William Fisher, Forrest Roberts and Ken Medlock, III, “BARNETT SHALE MODEL-1: Barnett study determines full-field reserves, production forecast,” OGJ, p. 62, August 5, 2013.
7.     Frank Male, Akand W. Islam, Tad W. Patzek, Michael P. Marder, Paper SPE168993-MS: “Analysis of Gas Production From Hydraulically Fractured Wells In The Haynesville Shale Using Scaling Methods,” presented at the SPE Unconventional Resources Conference – USA, held in The Woodlands, Texas, USA, 1-3 April 2014.
8.     Frank Male, Akand W. Islam, Tad W. Patzek, Svetlana Ikonnikova, John Browning and Michael P. Marder,  “Analysis of gas production from hydraulically fractured wells in the Haynesville shale using scaling methods,” submitted to the Journal of Unconventional Oil and Gas Resources, 2014 (now in revision to be send back to the editor).


  1. Patzek, T. W., Male, F. & Marder, M. Gas production in the Barnett Shale obeys a simple scaling theory. Proc. Natl Acad. Sci. USA 110, 19731–19736 (2013).

Ten years ago, US natural gas cost 50% more than that from Russia. Now, it is threefold less. US gas prices plummeted because of the shale gas revolution. However, a key question remains: At what rate will the new hydrofractured horizontal wells in shales continue to produce gas? We analyze the simplest model of gas production consistent with basic physics of the extraction process. Its exact solution produces a nearly universal scaling law for gas wells in each shale play, where production first declines as 1 over the square root of time and then exponentially. The result is a surprisingly accurate description of gas extraction from thousands of wells in the United States’ oldest shale play, the Barnett Shale.

The fast progress of hydraulic fracturing technology (SI Text, Figs. S1 and S2) has led to the extraction of natural gas and oil from tens of thousands of wells drilled into mudrock (commonly called shale) formations. The wells are mainly in the United States, although there is significant potential on all continents (1). The “fracking” technology has generated considerable concern about environmental consequences (2, 3) and about whether hydrocarbon extraction from mudrocks will ultimately be profitable (4). The cumulative gas obtained from the hydrofractured horizontal wells and the profits to be made depend upon production rate. Because large-scale use of hydraulic fracturing in mudrocks is relatively new, data on the behavior of hydrofractured wells on the scale of 10 y or more are only now becoming available.

There is more than a century of experience describing how petroleum and gas production declines over time for vertical wells. The geometry of horizontal wells in gas-rich mudrocks is quite different from the configuration that has guided intuition for the past century. The mudrock formations are thin layers, on the order of 30–90 m thick, lying at characteristic depths of 2 km or more and extending over areas of thousands of square kilometers. Wells that access these deposits drop vertically from the surface of the earth and then turn so as to extend horizontally within the mudrock for 1–8 km. The mudrock layers have such low natural permeability that they have trapped gas for millions of years, and this gas becomes accessible only after an elaborate process that involves drilling horizontal wells, fracturing the rock with pressurized water, and propping the fractures open with sand. Gas seeps from the region between each two consecutive fractures into the highly permeable fracture planes and into the wellbore, and it is rapidly produced from there.

Gas released by hydraulic fracturing can only be extracted from the finite volume where permeability is enhanced. Exponential decline of production once the interference time has been reached is inevitable, and extrapolations based upon the power law that prevails earlier are inaccurate. The majority of wells are too young to be displaying interference yet. The precise amount of gas they produce, and therefore their ultimate profitability, will depend upon when interference sets in.

For the moment, it is necessary to live with some uncertainty. Upper and lower bounds on gas in place are still far apart, even in the Barnett Shale with the longest history of production. Pessimists (4) see only the lower bounds, whereas optimists (19) look beyond the upper bounds. A detailed economic analysis based on the model presented here is possible, however, and is being published elsewhere (17, 18, 20, 21). The theoretical tools we are providing should make it possible to detect the onset of interference at the earliest possible date, provide increasingly accurate production forecasts as data become available, and assist with rational decisions about how hydraulic fracturing should proceed in light of its impact on the US environment and economy.

  1. Browning, J. et al. Oil Gas J. 111 (8), 62–73 (2013).
  2. Browning, J. et al. Oil Gas J. 111 (9), 88–95 (2013).
  3. Browning, J. et al. Oil Gas J. 112 (1), 64–73 (2014).
  4. Gülen, G., Browning, J., Ikonnikova, S. & Tinker, S. W. Energy 60, 302–315 (2013).
  5. Weijermars, R. Appl. Energy 124, 283–297 (2014).
  6. Kaiser, M. J. & Yu, Y. Oil Gas J. 112 (3), 62–65 (2014).
  7. Hughes, J. D. Drilling Deeper (Post Carbon Institute, 2014); available at and Hughes JD (2013) Energy: A reality check on the shale revolution. Nature 494(7437):307–308
  8. Cook, T. & Van Wagener, D. Improving Well Productivity Based Modeling with the Incorporation of Geologic Dependencies (EIA, 2014); available at
  9. US Energy Information Administration Technically Recoverable Shale Oil and Shale Gas Resources (EIA, 2013); available at
  10. Assessment of Shale Gas and Shale Oil Resources of the Lower Paleozoic Baltic–Podlasie–Lublin Basin in Poland — First Report (Polish Geological Institute, 2012); available at
  11. Assessment of Shale Gas and Shale Oil Resources of the Lower Paleozoic Baltic–Podlasie–Lublin Basin in Poland — First Report (Polish Geological Institute, 2012); available at


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