by Peter Zeihan
Scared New World: Losing Interest
The demographic inversion will also have one additional impact on the international order: that of disconnecting the Americans. Economically, global trade is predicated on the ability to sell into growing markets. In the post–World War II era it has been the American market that has always been far and away the largest, and even in the most egregiously optimistic estimates for Europe and the BRICs it will remain so for at least the next twenty years.
Those egregious growth estimates, however, fail to take into account the chronic aging occurring throughout most of the world. Within a decade it isn’t so much that the American market will be the largest one in the world, but that aging demographics will have capped—and in most cases reversed—consumer market growth in Japan, Germany, the United Kingdom, China, Italy, Canada, Spain, Russia, Korea, the Netherlands, Switzerland, Belgium, South Africa, Austria, Greece, Norway, Denmark, Portugal, and Finland. That’s not simply over half of the world’s thirty largest economies, but it also includes most of the countries that the Americans created Bretton Woods for in the first place. If they are no longer consuming en masse, then much of what limited economic rationale exists for Bretton Woods disappears from the American point of view.
Couple that market degradation with America’s Gen Y demographic regeneration, and as early as 2030 the United States will emerge as the only country that is capital-rich, the only country with a growing economy, and the only country with a growing market. And all this without any conscious demographic policy on the part of the Americans.
If that wasn’t enough, the Americans have yet one more thing going for them that will magnify all of these advantages. We’ll cover it in the next chapter.
CHAPTER 7
The Rise of Shale
Americans have a love-hate relationship with the petroleum industry. They love having cars and air-conditioning, but hate pollution, global warming, and the environmental damage associated with exploding rigs or tanker spills. Yet no matter how Americans feel or how loudly they may complain, the simple fact remains that fossil fuels are their way of life. In terms of total American energy usage—whether it be from electricity production, chemical production, or transport fuels—by their own government’s numbers, 34.7 percent originates from oil, 26.0 percent from natural gas, 17.4 percent from coal, 8.1 percent from nuclear, 5.5 percent from hydropower, and only 3.4 percent from nonhydro renewables like solar and wind. That’s 80 percent of the total from fossil fuels. The same love-hate dichotomy applies to the shale industry.
I’m going to take us on a quick tour through the industry to help explain this disconnect. The point of doing so is not simply to show that shale is already a done deal—at the time of this writing the shale industry already produces a majority of American oil and natural gas output—but rather that public opposition to shale will soon crumble. When that happens, the full impact of shale will be realized, which in turn will unleash global trends that will underpin American power for the next several decades.
A Bit of Geology to Set the Mood
Let’s start with the basics of petroleum1 and shale.
Most petroleum formed as a result of life-forms—typically plankton—being trapped in layers of sedimentary rock. After millions of years of heat and pressure, these critter corpses cook into petroleum, which percolates up through the rock until it reaches a formation through which it cannot pass. These cap rocks allow the petroleum to collect into large pools. Most of the petroleum harvested around the world over the past couple of centuries has come from such “conventional” reservoirs.
But not all petroleum is located in large, easy-to-stick-a-straw-in pools. If the rock in which the oil and natural gas was formed is not porous, then the petroleum remains trapped where it was created rather than slowly collecting into an area where it can be easily harvested. In such rock formations the petroleum remains finely distributed, trapped between individual rock particles. The result isn’t so much like chips in a cookie, but instead like the booze in a dry rum cake. The rum is there, suspended within a matrix of cooked batter. It is a devil of a task to coax it out. Data is far from complete, but most recent estimates project that some 90 percent of the world’s petroleum is locked into such geologies. Even if such estimates are wrong by an order of magnitude, it suggests that the amount of petroleum in the wider world is double what we thought it was just a decade ago.
One of the major types of rock formations that trap petroleum in this way is called shales. Shales are sedimentary rocks, deposited hundreds of millions of years ago at the bottom of oceans. Because of their ocean-floor origins, they are typically found in long, thin horizontal layers covering up to tens of thousands of square miles. As with other unconventional petroleum basins, the ultra-fine distribution of shale petroleum makes the use of conventional energy production technologies largely useless.
So the energy industry had to get unconventional.
The integration of two unrelated technologies is what has brought us the shale era. The first technology is horizontal drilling. Your traditional petroleum well is a purely vertical affair. If you happen to miss in your downward drilling, tough. If you hit a particularly slanted formation on the way down that breaks your vertical descent, tough. If there is a particularly hard rock on the way down that you cannot drill through, tough. Horizontal drilling allows you not only to drill laterally but also at angles and around corners—even around multiple corners—to weave your way through complex formations to reach exactly where you want to go. A typical vertical well might only expose ten feet of petroleum-rich rock, but a typical horizontal well exposes up to a mile. As seismic detection techniques have improved in reach and precision, horizontal drilling has both made preexisting petroleum fields more productive and enabled energy firms to bring previously unreachable deposits online. In regions with less than stellar technology—Cuba comes to mind—horizontal drilling has allowed onshore producers to reach a few miles into offshore environments by drilling hard up on the coast but sending their drill shafts out under the seabed.
The second tech, hydraulic fracturing, uses water pressure to crack rock. In hydraulic fracturing, petroleum engineers inject a 90 percent water mixture down the well shaft and into the rock formation. Liquids, unlike gases, do not compress under pressure, and so the rock becomes spiderwebbed with billions of tiny cracks. Included in the liquid mixture is something called a proppant—typically some sort of sand—that wedges itself into those cracks. The rock itself absorbs some of the liquid and the rest is sucked back to the surface to be recycled. But most of the proppant stays behind, propping the cracks open. Those cracks provide pathways for the no longer trapped petroleum to flow to the well shaft.
In essence, hydraulic fracturing forces a nonporous rock to be partially porous. But not porous like the sort of rock formations that generate traditional petroleum deposits. Instead of allowing the bits of petroleum to slowly percolate upward over the millennia, fracturing enables them to travel only along the new specifically engineered fractures directly to the well shaft.
The use of these two technologies in tandem—colloquially if somewhat inaccurately known as fracking—is the basis of the shale energy boom.
The focused specificity of fracking technologies sets off a very predictable chain of events. Once the cracks reach the trapped petroleum it flows out (well, up) with considerable speed. At first. Remember that these techniques tap a reservoir, but one in which the petroleum is highly sequestered and barely connected by fractures. Only those elements directly connected to the fractures can flow at all, and they can only flow to the borehole. The result is an initial burst of petroleum output, followed almost immediately by a quick drawdown. In most areas one-third of the total output of a well comes in the first year or two of its twenty-year life span.
The most obvious implication of this quick bleed-off is that if a shale energy industry is going to maintain—much less grow—its output, then a lot of wells need
to be drilled every single year. In the United States that comes out to about fifty thousand fracked wells a year. That sounds like a lot. It is a lot. Since fracking took off less than a decade ago, the total number of petroleum wells in the United States has doubled.
Sustainable Shale
Yet this is a pace that the Americans can keep up for a very long time. It is difficult to provide accurate data as to baseline information such as production rates or reserves, not because such data is unavailable, but instead because the newness of the industry means it is changing so quickly.
In August 2012, the Energy Information Agency, an office within the U.S. Department of Energy, released a comprehensive report on the then reality of shale energy. The EIA used the best data available at the time, which had been gathered by December 2011. They pegged American shale oil output at 2 million bpd, about the same as Norway’s shale output. They also made projections as to how shale output would unfold over the next eight years. When this report came out it was the definitive work on the reality of shale.
A mere one year later that report was hideously out of date. With fifty thousand (or more) new wells coming online annually, keeping tabs on those wells across hundreds of legal jurisdictions is a logistical impossibility. And as is common in any high-value-added industry, innovations do not require government approval, registration, or even notification. Such innovations are, however, applied to every well the rig crew works from that point on. The result is an ever-building skill set that spreads and compounds throughout the industry. In December 2013, only sixteen months after the EIA’s exhaustive report, shale oil output had increased from 2 million bpd to 3.8 million bpd—that’s not only more than Canada’s oil output, but is about 50 percent more than the EIA’s projection for U.S. shale oil output for 2020. At the time of this writing in mid-2014, even that data is now outdated. As of 2014 the United States is now the world’s largest energy producer, bringing up more oil than Saudi Arabia and more natural gas than Russia.
What will U.S. shale output look like in the future? Details are murky: There are many shifting variables, there is no such thing as “average” when considering an industry that operates in wildly varied geologies and regulatory environments, and any estimate provided now likely will be overwhelmed in the time it takes this manuscript to make it into print.
But caveats aside, the learning curve is still extraordinarily steep, with huge gains being made at nearly every stage of the process. Deeper wells, longer horizontal shafts, more controlled and therefore more effective fracking, better fluids, more detailed imaging, more experience using recycled and subsurface water all add up to better reach, lower costs, and higher recovery rates. From 2012 to 2013 alone half as many rigs were able to generate the same output. “Overall” break-even prices for natural gas production have probably dropped from about $7 per 1,000 cubic feet in 2011 to under $5 in 2014. Similarly, the break-even price for shale oil production has dropped from over $100 per barrel a decade ago to $85 in 2011 to probably something closer to $70 in 2014, with many basins already nudging toward $50.
It is now a fairly conservative estimate to say that North America will be fully energy independent by 2020. We are not at the dawn of the shale era. We are already in the shale era.
(On the Verge of ) Shale Acceptance
Yet Americans still do not trust the industry. In a September 2013 survey, Pew Research found that 49 percent of Americans oppose increased use of shale energy techniques. Specifically, Americans are concerned that fracking uses huge volumes of water, that frack fluid is toxic at best and carcinogenic at worst, and that the frack fluid leaks out of the well shafts and into the aquifers that supply drinking water. It is difficult to square the importance and growth of the shale industry with the circle of public concern. Luckily—for both—I expect that most of the public’s distrust for the shale-related techs will evaporate within a few short years. There are three reasons for this.
First, the use of surface water is quickly being phased out in fracking operations. Surface water is full of algae and bacteria; such impurities must be removed to make water suitable for fracking. One of the more expensive portions of fracking fluids is the various chemicals required to purify the water. Add in the cost of trucking millions of gallons of water around (high-bulk cargo, high-cost transport), and surface water use is as much an economic issue for the shale industry as it is a quality-of-life issue for local communities. Luckily, subsurface drilling has discovered layers of mildly saline brackish water deep underground2 in almost all regions. Energy firms have discovered that this lifeless, nonpotable water provides a better medium for frack fluids. And because a wellbore at the drilling site can access this brackish water and the frack additives can be mixed with it on site, all those trucks that needed to bring millions of gallons of water per well3 are suddenly not needed. By 2016, large-scale surface water use will continue only in those few areas that do not have a brackish water layer.
Second, most aquifers that supply drinking water are within two hundred feet of the surface, and nearly all are within six hundred feet.4 Some 90 percent of fracks occur at over a mile of depth, with only a handful completed at less than four thousand feet. The longest frack cracks ever completed are but six hundred feet long, with the vast majority being no longer than two hundred feet;5 with recent advances most fracks are often as short as forty feet. That puts a minimum of a half mile of solid rock—remember that by definition shale formations are impermeable—between the frack cracks and the water supply. It adds up to a simple fact: There has never been a case of fracking fluid subsoil contamination of drinking water. But don’t believe me. Believe the EPA under the Obama administration. Out of the roughly 1.2 million that have been fracked in the United States since the Truman administration, the EPA has yet to issue a single citation to any firm anywhere in the country for subsoil contamination due to frack fluid.6
What citations the EPA have issued fall into two categories. The first, surface water contamination, makes up over 90 percent of the citations. It is largely an issue of drillers discharging recovered frack fluid into surface streams. (Such practices were actually legal in many states at the beginning of the shale era!) The second is various forms of methane (another term for natural gas) leakage, whether that occurs in the well shaft, the pad, or the transport system (more on that later). Methane leakage has been a regulatory and environmental concern for as long as there has been a natural gas industry. The biggest new challenge such leakage presents is that there are so many more wells in a shale field than in a conventional field that operators—and regulators—need to be scrupulous about well completion. Aside from that there is nothing that makes leakage from shale wells technologically different from any other well.
The third reason shale energy is going to become more publicly acceptable is that despite the public firestorm, frack fluid isn’t all that dangerous and is edging toward becoming completely nontoxic. While there is considerable variation in ingredient proportions, the ingredients themselves are well known. All are approximately 90 percent water, 9.5 percent sand. For the remainder, the dominant ingredients are borates (a key component in laundry detergent), n-dimethylformamide (plastics), ethylene glycol (antifreeze), guar gum (ice cream), and isopropanol (glass cleaner). While it would be best to not drink the stuff, there is nothing in the components that isn’t already cleared for presence in the average kitchen. Regardless, the industry has noted the public outcry and has been steadily removing all toxicity from the chemical mix. In 2011 Halliburton introduced a new frack fluid made entirely of components from the food industry, which Democratic Colorado governor John Hickenlooper made famous by taking a swig.7 Other chemicals firms have followed suit, and disclosure of the various fluids’ components is starting to be shared more readily in an effort to defuse the issue. The price difference is on average only 5–10 percent.
Once it is clear that surface water use has plummeted, that the Obama administration has signed off on the i
ndustry as a whole, and that the frack fluid itself goes reasonably well with tomatoes and mozzarella, the controversy surrounding shale will simmer down. In a few short years opposition will be limited to two groups: environmentalists who are opposed to any petroleum developments on principle, and local groups who don’t perceive any personal benefits. This is not an inconsequential slice of the American electorate, but it is probably only about 10 percent of the population.
Shale: An Industry That Speaks with an American Accent
So American shale is not only a done deal, but it is also about to accelerate considerably. What is even more notable about shale is that it will remain American for quite some time. It is extremely unlikely that the shale technologies will be applied en masse anywhere outside of North America before 2035. Why? Shale success reflects many features of the American system that we have already discussed. There are four factors that must exist simultaneously for a country to birth a shale industry in short order:
1. Huge, Deep Capital Markets
You have to throw a lot of money at a fracking project to get results. As with everything else about shale, there is no average, but costs can be extreme and typically everything—roads, pipes, drills, and labor sufficiently skilled to drill a mile beneath their feet—has to be paid up front. Rigs—whose rates include labor—rent at anywhere from $10,000 to $100,000 a day. An easy well might “only” take eight days, but difficult wells can be five times that. A low-end figure is usually in the range of $6 million per well.
