Snake Oil: How Fracking's False Promise of Plenty Imperils Our Future (9 page)

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.
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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.
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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.”
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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.”
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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.”
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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.
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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.”
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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.

For every play there are only so many places to drill. For the Eagle Ford, the EIA estimates a total of 11,406 effective locations. With a 40% overall field decline rate, and assuming current rates of drilling with all new wells performing as in 2011, Hughes anticipates a peak of production in the Eagle Ford in 2016 at 0.891 million barrels per day.
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Total oil recovery is estimated at about 2.23 billion barrels by 2025, amounting to a five-month contribution to US oil consumption.
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More than 80% of current tight oil production in the United States comes from the Bakken and Eagle Ford, with the other 20% issuing from 19 other formations. Estimates suggest the biggest prize of all could be the Monterey shale in California, with 41% of America’s total purported tight oil resources. But Hughes is not optimistic about the Monterey play’s prospects: “Recent drilling results have been disappointing and the longer- term performance of the Monterey is mostly at ‘stripper well’ levels . . . with an average of 12.7 barrels per day from [each of] 675 wells. This bears no comparison to the Bakken or Eagle Ford.”
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The problem is geological: California’s seismic history has left the Monterey shale heavily faulted, folded, and fractured, presenting drillers with far more expensive complications than ones they face in North Dakota and Texas.
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The United States’ total tight oil “technically recoverable unproved resources” are estimated at between 23 and 34.6 billion barrels (assuming that 13.7 billion barrels can be produced from the Monterey play). “Although significant,” writes Hughes, “this is hardly cause for celebrating US ‘energy independence,’ as it represents somewhere between three and four years of consumption, even if it all could be recovered—which would take decades.”

Will the Rest of the World Get Fracked?

Some fracking boosters claim that the United States is merely the thin end of a wedge, and that the same technology that opened up the Barnett and Bakken will soon liberate oil and natural gas from similar reservoirs in China, Europe, and elsewhere. How likely is this?

The US fracking boom is several years old now, and so far little shale gas or tight oil production is occurring in other parts of the world. This could simply be a problem of timing: perhaps the rest of the world will eventually catch up with North America. On the other hand, there could be fundamental barriers to the widespread application of fracking technology outside the United States. Let’s explore the factors at work and see whether they support an expectation of worldwide shale gas and tight oil abundance.

Some countries have banned, tightly regulated, or put off fracking for environmental reasons. Outright bans have been enacted in France, Luxembourg, and Bulgaria. In Germany, Poland, and the United Kingdom, tight regulations constrain drillers. Throughout most of Europe there is strong public opposition to fracking on environmental grounds. Whether these are temporary or persisting impediments to industry development will depend on forthcoming revelations about the environmental safety of fracking, and on industry efforts to address the problems. As we’ll see in Chapter 4, the impacts to air quality, water quality, and climate from shale gas and tight oil production are hardly trivial.