These are questions best answered by data—by realistic resource estimates, per-well production and decline rates, and reliable calculations of the number of possible drilling sites. Compiling these kinds of data is hard work and often requires access to expensive proprietary information. And the rewards are few: investors want good news.
In the previous chapter we surveyed the claims made by the industry regarding reserves and future production of shale gas and tight oil. This chapter tells the story of the data—how they have evolved, and what they tell us now.
THE BOOM THAT FIZZLED
The first indication that the emerging shale gas bonanza might not have a happy ending came in 2007 when Arthur E. Berman, a petroleum geologist and consultant to the oil and gas industry in Sugar Land, Texas, started crunching numbers from the Barnett shale gas play. The results were anything but encouraging. Berman used his regular column (“What’s New in Exploration”) in World Oil magazine to report on his analysis of decline rates and profitability for hydrofractured, horizontally drilled Barnett wells and concluded: “This analysis shows that, while many wells are profitable and some operators are significantly more successful than others, most Barnett shale wells will lose money. . . . The overall resource size for the play is great, but economic reserves are relatively small.”
Berman continued accumulating data from shale plays and publishing his analyses; the following paragraph, from his March 6, 2009, World Oil column titled “Shale Plays, Risk Analysis and Other Perils of Conventional Thinking: Haynesville Shale Sizzle Turns to Fizzle,” is typical of his coverage:
An early analysis of 20 horizontally drilled wells in the Haynesville Shale play in Louisiana and parts of adjacent East Texas suggests a disappointing outcome because of extremely high decline rates. Average monthly decline rates are 24%, with 75% of wells declining 20–35% per month. The impressive initial production rates (IP) for these wells do not, therefore, necessarily translate into high reserves (actual daily production rates from the maximum 30-day period were, in fact, about 20% lower than reported IPs).
Representatives of the shale gas industry hotly denied Berman’s assertions, accusing him of “inconsistent data gathering” and of having “poorly supported opinions.” After all, total production in the shale gas plays was rising, companies were flush with investment capital, and jobs were being created. How could this be anything less than a game-changing economic miracle?
In October 2009, Berman wrote yet another column questioning shale gas prospects; this time World Oil refused to run it. Berman recounted the events this way when I e-mailed him:
Perry Fischer, the editor of World Oil, called to tell me that my column in press would be pulled because of objections from Petrohawk Energy and Seneca Resources. I later had a conversation with John Royall, President and CEO of Gulf Publishing that owns World Oil, who objected to my comments to the press that he had been pressured by industry not to publish my articles on shale. My relationship was based on freedom to choose content. Since the magazine rejected content, I chose to end the relationship.
The incident was reported in the Houston Chronicle (Nov. 3), which noted:
John Royall . . . said he didn’t receive any pressure from gas companies. World Oil serves a global audience, and gas shale is largely a domestic issue. Berman had written on the topic for a year, and Royall decided that was enough. “Art had an interesting take on shale gas,” he said. “It was interesting, provocative stuff, but it was time to move on.”1
Berman continued gathering data, doing the numbers, and writing his conclusions in articles published at TheOilDrum.com and on his own his own blog, PetroleumTruthReport.blogspot.com. He also gave public presentations, including one at the 2009 ASPO-USA conference in Denver, where I first heard him speak.
By 2011, Berman had been joined by other critics of the shale gas boom. Bill Powers, editor of Powers Energy Investor and previously the editor of the Canadian Energy Viewpoint and US Energy Investor, began telling his readers about high decline rates and other problems repeatedly and in detail, relying mostly on Berman’s analysis. “The importance of shale gas has been grossly overstated,” Powers told TheEnergyReport.com. “The US has nowhere close to a 100-year supply. This myth has been perpetuated by self-interested industry, media and politicians.”2 Soon Powers began working on a book, Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth, published earlier this year. Art Berman contributed the book’s foreword.
Berman’s work also served as initial inspiration for a major new analytic survey, the most comprehensive to date, authored by David Hughes and published by the Post Carbon Institute (at which I am senior fellow) in February 2013.3 Hughes, a geoscientist who studied the energy resources of Canada for nearly four decades, including 32 years with the Geological Survey of Canada as a scientist and research manager, examined proprietary data on 63,000 US shale gas and tight oil wells, calculating production decline rates in each active play. The data were licensed from DI Desktop. (DI stands for DrillingInfo, a petroleum industry data company headquartered in Austin, Texas.) Hughes’s report fills over 160 pages, including many tables and graphs, and also addresses prospects for expanded production of tar sands and other unconventional fuels. For anyone wanting to understand current and future production from fracking and horizontal drilling, “Drill, Baby, Drill” is the Holy Grail of information and analysis. Here’s the report’s abstract:
It is now assumed that recent advances in fossil fuel production—particularly for shale gas and shale oil—herald a new age of energy abundance, even “energy independence,” for the United States. Nevertheless, the most thorough public analysis to date of the production history and the economic, environmental, and geological constraints of these resources in North America shows that they will inevitably fall short of such expectations, for two main reasons: First, shale gas and shale oil wells have proven to deplete quickly, the best fields have already been tapped, and no major new field discoveries are expected; thus with average per-well productivity declining and ever-more wells (and fields) required simply to maintain production, an “exploration treadmill” limits the long-term potential of shale resources. Second, although tar sands, deepwater oil, oil shales, coalbed methane, and other non-conventional fossil fuel resources exist in vast deposits, their exploitation continues to require such enormous expenditures of resources and logistical effort that rapid scaling up of production to market-transforming levels is all but impossible; the big “tanks” of these resources are inherently constrained by small “taps.”4
From the work of Berman, Hughes, and other analysts, a more realistic picture of the actual potential of shale gas and tight oil plays is emerging. Briefly: The wells in core areas (usually just a few counties) in each of these plays do tend to be productive and profitable, yielding oil or gas in significant amounts for many years. These are not comparable to the conventional oil and gas finds of the mid-20th century, but they do nevertheless provide an important new source of supply for the industry and for the nation. However, these compact core areas tend to be drilled out fairly quickly. Meanwhile, outside these regions, per-well production rates tend to fall quickly and dramatically, and wells are uneconomic. Overall, taking into account decline rates, potential drilling locations, and the variability of regions within resource plays, the industry’s claims for how much oil and gas can be extracted, at what rate, and how profitably, are wildly overblown.
Throughout much of the rest of this chapter, as we explore the energy reality of fracking in more detail, we will be relying primarily on data and analysis in “Drill, Baby, Drill.”
SHALE GAS: THE EVIDENCE IS IN
When discussing US shale gas production, it is always necessary to begin by acknowledging the industry’s accomplishments—as we have already done on more than one occasion in this book. Natural gas production in the United States is now higher than at any point in history, and shale gas currently makes up 40% of America’s total natura
l gas production. Considering how quickly the new technology has been deployed, this is an impressive achievement.
Nevertheless, it turns out that high productivity shale gas plays are few and far between: just six plays account for 88% of total production. And, as noted at the end of Chapter 2, each play is in effect its own “resource pyramid,” characterized by a few small “sweet spots” surrounded by larger areas capable of only marginal productivity. Drillers invariably concentrate their efforts on the zones of highest productivity first. So, as time goes on and as drillers must stray ever further from sweet spots, the initial productivity of each new well drilled in the play tends to be lower than that of previous wells. The number of available drilling sites is always limited, and, once the play is saturated with wells, per-well decline rates will determine the play’s longevity.
Hughes notes that individual shale gas well decline rates range from 80–95% after 36 months, in the top five US plays. The industry’s claim that America has 100 years of gas is based on the assumption that individual wells will continue to produce for 40 years, but given such steep decline rates, the data do not support this assumption.
Figure 19. Type Decline Curve for Barnett Shale Gas Wells. Based on data from the most recent five years of this play’s production.
Source: J. David Hughes, “Drill, Baby, Drill,” Figure 48. Data from DI Desktop/HPDI current through May 2012.
One result of high decline rates is that a large proportion of overall field output must be replaced by additional drilling in order to keep the total production rate growing or even flat. Hughes calculates that, for the nation as a whole, between 30 and 50% of shale gas production must be replaced every year with more drilling—amounting to roughly 7,200 new wells a year. Remember: that’s simply to maintain the current production rate. This is the “treadmill to hell” referred to in the title of this chapter. Oil analyst Rune Likvern uses a different metaphor; he calls it the “Red Queen” syndrome, after a character in Lewis Carroll’s Through the Looking-Glass. In that colorful story, the fictional Red Queen jogs along at top speed but never gets anywhere; as she tells Alice, “It takes all the running you can do, to keep in the same place.” Similarly, with such steep decline rates, it takes all the drilling that the industry can do just to keep production steady.5
There were 341,678 operating gas wells in the United States in 2000, prior to the fracking revolution, representing more than a century of drilling efforts. In 2011, that number had swollen to 514,637.6 Here again is evidence that descent to lower levels of the “resource pyramid” ensures diminishing returns from increasing effort: since 1990 the average productivity per well has declined by 38%.
The EIA reports these trends but still believes shale gas production rates can continue to grow. What would it take to make that happen? Only a drilling pace that’s utterly unprecedented can possibly suffice. In the 2005–2008 period, the industry roughly tripled the number of natural gas wells being drilled annually, as compared to 1990s’ rates. To produce the estimated US reserves of shale gas, the EIA calculates that 410,722 shale gas wells will have to be drilled.7 It takes a moment to mentally process the implications of drilling on that scale.
Obviously, this would represent an enormous, unprecedented investment on the part of the gas industry. Already, dry shale gas plays require $42 billion per year in capital investment in drilling in order to offset declines. Given current low natural gas prices (as of this writing, natural gas is selling for about $4 per million Btus), this investment is not recouped by sales: in 2012, US shale gas generated just $33 billion in revenues. As we’ll see in more detail in Chapter 5, gas drilling companies are staving off bankruptcy through a variety of strategies, including asset sales and increased production of liquid fuels. How realistic is it to assume that these companies will double down on their dry gas drilling investments during the next couple of decades, absent much higher gas prices?
And what do these trends suggest about the reliability of shale gas reserves numbers? Clearly, shale gas resources do exist in enormous quantity. But reserves are always a fraction of the total resource base. Some reserves are termed technical reserves: these are resources that theoretically could be extracted given current technology. A smaller but more important category consists of economic reserves: these are resources that can profitably be extracted with current technology and at current prices. If the industry is, on the whole, losing money on shale gas production, this suggests that US economic reserves of shale gas are in fact fairly modest. At higher prices, more resources would fall into this category. If gas prices were $15 per million Btus (as they already are in some parts of the world) instead of $4, then economic reserves would grow accordingly. But the American people are being led to believe that most of the shale gas resource base can be produced at a price low enough so as to enable natural gas to be used for the majority of power generation, and even as a substitute for gasoline in tens of millions of cars and trucks. This is pure folly.
Finally, what are we to make of the familiar claim that the United States is sitting on a hundred years’ worth of natural gas? It is clearly not based on realistic public data. The EIA lists proved and unproved technically recoverable shale gas reserves at almost 600 trillion cubic feet (tcf). This is 24 years of natural gas supplies at current US consumption rates. But even this 24-year supply estimate is questionable. David Hughes notes: “This is an extremely aggressive forecast, considering that most of this production is from unproved resources, and would entail a drilling boom that would make the environmental concerns with hydraulic fracturing experienced to date pale by comparison.”8
Rafael Sandrea of IPC Petroleum Consultants, in a report titled “Evaluating Production Potential of Mature US Oil, Gas Shale Plays,” notes that unusually high field decline rates associated with shale gas plays imply low recovery efficiencies. “The average recovery efficiency is about 7%,” he writes, “in contrast to recovery efficiencies of 75–80% for conventional gas fields. This suggests that the estimate of recoverable gas for all US shale plays should be near 240 tcf.”9 Which is less than 10 years of current United States natural gas consumption.
Figure 20. EIA Projection of US Natural Gas Supply by Source, 2010–2040. In this projection, shale gas accounts for 50% of production in 2040.
Source: J. David Hughes, “Drill, Baby, Drill,” Figure 32; data from Energy Information Administration, Annual Energy Outlook 2013 (Early Release), Tables 13 and 14.
BAKKEN BOOM, BAKKEN BUST
The situation we’ve just surveyed with regard to shale gas is largely mirrored in the tight oil plays of North Dakota and south Texas. Again, per-well production decline rates are steep—between 81 and 90% in the first 24 months. Production from individual wells tapers off so quickly that 40% of overall output (from older wells with lower decline rates along with output from newer ones) must be replaced annually by new drilling just to keep the total supply curve flat. According to Hughes, “Together the Bakken and Eagle Ford plays may yield a little over 5 billion barrels—less than 10 months of US consumption.”10
The Bakken play had produced 0.5 billion barrels through May 2012, with an estimated ultimate recovery of about 3 billion barrels by 2025. On one hand, this represents a remarkable accomplishment: who in 2000 or even 2005 expected North Dakota to become a major oil-producing region? Yet the achievement requires extraordinary effort. Drillers can’t let up; if they do, high per-well decline rates will ensure falling overall production.
An article by Jaci Conrad Pearson in the Black Hills Pioneer (September 19, 2012) titled “It Takes Oil Money to Make Oil Money” captures the expense of an enterprise involving hundreds of companies and thousands of wells:
“It takes $3 per second, $180 per minute, $10,800 per hour and $259,000 a day to drill an onshore well,” said Kent Ellis, owner of Aurora Energy Solutions, LLC, an oil and gas brokerage firm with offices in Bismarck, ND and Oklahoma City, Oklahoma, during his address to a crowd of more than 100 gathered
for his presentation as part of the Black Hills Pioneer’s Oil, Gas and Mineral Rights Workshop. “. . . It takes 2,200 gallons-plus of diesel fuel a day, just to run the rig.” And moving the rig is another story and another significant cost. “To move a rig from Spearfish to Belle Fourche costs around $250,000,” Ellis said.11
Figure 21. Type Decline Curve for Bakken Tight Oil Wells. Based on data from the most recent 66 months of this play’s oil production.
Source: J. David Hughes, “Drill, Baby, Drill,” Figure 63; data from DI Desktop/HPDI current through May 2012.
This is not your grandfather’s oil business. Tight oil deposits are typically thinner than those in conventional wells, with layers of oil-bearing rock sandwiched between other rock layers. Horizontal drilling enables the operator to go after oil deposits from the side, yielding much higher recovery than a vertical well could achieve. But it also implies a dramatic production decline curve. In effect, operators must chase the deposit sideways, and the cost of drilling horizontally in pursuit of the ever-retreating reserve quickly escalates. “Eventually,” according to Robert Smith, operations geologist with International Western Oil, “horizontal drilling is suspended because operators reach a point where they are just burning cash.”12
Figure 22. Future Oil Production Profile for the Bakken Play, Assuming Current Rate of New Well Additions. Based on data from the most recent 66 months of this play’s oil production.
Source: J. David Hughes, “Drill, Baby, Drill,” Figure 66; historical data from DI Desktop/HPDI current through May 2012.
The Eagle Ford is younger in its production cycle than the Bakken. Operators there are still in the process of identifying sweet spots; while they find and drill these optimum locations, average initial production rates are still rising. Still, Eagle Ford decline rates are even higher than those observed in the Bakken. The first-year decline in production in new Eagle Ford wells is 60% and the overall decline at the end of the second year is 89% below the average initial production levels of wells drilled in 2012. These decline rates mean the average Eagle Ford well will enter the category of “stripper” well (yielding fewer than 15 barrels per day) within about three years.
Snake Oil: How Fracking's False Promise of Plenty Imperils Our Future Page 7
