As mentioned in the introduction, hydrofracking is defined in different ways by different people. To those in the energy industry, it refers purely to the process of injecting fluid—which consists of water and between 3 and 12 chemicals, including hydrochloric acid, sodium chloride, methanol, and isopropyic ethanol, that serve various functions—underground at high pressure to crack open shale rock, release natural gas or oil trapped there, and allow the hydrocarbons to flow to the surface.1 Energy specialists will point out that hydrofracking and drilling are not the same thing. First comes drilling of the wells, then comes the hydrofracking.
But such distinctions are lost on the public. To most people, hydrofracking and drilling are simply two parts of one process. In this broader definition, “fracking” is a shorthand way to describe all of the steps used to prepare a well, drill it vertically and horizontally, inject the fluid, recover hydrocarbons, and remediate the waste. For the sake of clarity and brevity, I have used the latter, broader definition in this book.
Fracking has emerged as a central issue in part because of the significant changes we are seeing in today’s energy landscape. According to the EIA, total energy consumption in 2008 by the global population of seven billion was 493 quadrillion BTUs—or 493,000,000,000,000,000 BTUs.2 As the global population expands to nine billion by 2040, the demand for affordable, reliable, plentiful energy supplies will increase exponentially. Daniel Yergin, a leading energy consultant and Pulitzer Prize–winning author of books such as The Quest: Energy, Security, and the Remaking of the Modern World, predicts that global energy demand will increase 35 to 40 percent in the next two decades alone. “Much of the infrastructure that will be needed in 2030 to meet the energy needs of a growing world economy is still to be built,” he has said.3
The United States has long held the title for the world’s largest economy, and has been as well its foremost energy user. With less than 5 percent of the world’s population, the United States consumes 20 to 25 percent of the world’s supply of fossil fuels.4 But in 2010 China surpassed the United States to become the globe’s biggest energy consumer: the United States uses 19 percent of the world’s energy, and China accounts for 20.3 percent of global energy use.5 By 2016, the International Monetary Fund (IMF) forecasts, China will eclipse the United States as the world’s leading economy.6
As concern about rising global temperatures, high oil prices, the vulnerability of nuclear plants, and friction over energy supplies grows, there will be calls for greater use of “renewables”—sunlight, wind, moving water, and geothermal heat. A shift to new technologies and fuels is already under way, and defining what resource economists call “a new age in the history of energy.”
The American public, for one, seems to favor a cautious approach. In the US presidential election of 2012, Republicans and Democrats sparred over energy policy, among many other issues. But political theater aside, Obama and Governor Mitt Romney agreed on most issues: both said they wanted to lower dependence on oil from the Middle East and to encourage more oil drilling in Alaska, Texas, North Dakota, and the Gulf of Mexico. Both said they supported biofuels and nuclear power. And each candidate asserted that he would promote hydrofracking better than his competitor.
While the public generally associates hydraulic fracturing with natural gas, the process is also used for many other purposes, including
• Extracting oil and “liquid” natural gases (LNGs), such as propane, butane, hexane, and the like
• Preventing mining cave-ins
• Stimulating or gauging groundwater flow
• Accelerating the flow of water from drinking supplies
• Injecting wastewater (including from hydrofracking) into deep rock formations for permanent storage
• Disposing of oil or gas waste, and remediating Superfund sites (i.e., places with the highest levels of pollution in the country)
• Extracting geothermal heat from underground to produce electricity
• Increasing injection rates for geologic sequestration of CO27
Originally, vertical wells tapped oil- or gas-bearing limestone or sandstone formations, which are relatively porous. Natural gas was first extracted from shale rock in Fredonia, New York, in the 1820s by means of conventional drilling. The first fracturing of shallow, hard-rock wells occurred in the 1860s, when prospectors in Pennsylvania, New York, Kentucky, and West Virginia used nitroglycerin (NG) to search for oil in shale formations. Though NG could explode and its use was illegal, the technique was extremely successful. Later, the same methods were employed in water and gas wells. But it was Floyd Farris, of Stanolind Oil and Gas Corporation (an exploration and production business started by Indiana Standard in 1931, which later became Amoco, now part of BP), who conducted experiments in the 1940s and saw the potential of hydraulic fracturing to enhance production from oil and gas wells. The first attempt to “hydrafrac” a well took place in the Hugoton gas field in Grant County, Kansas, in 1947: Stanolind injected 1,000 gallons of gelled gasoline and sand taken from the Arkansas River into a gas-bearing limestone formation 2,400 feet deep. The experiment was not a huge success, but it led to further experiments by Stanolind. A patent on the process was issued in 1949, and an exclusive license for its use was granted to the Halliburton Oil Well Cementing Company (Howco) of Texas. Howco performed the first two commercial hydraulic (water-based) fracturing treatments, in Stephens County, Oklahoma, and Archer County, Texas. The process was used on 332 wells in 1949, and production increased a surprising 75 percent. At first, crude oil, gasoline, and kerosene were used as fracturing fluids. But in 1953, they were replaced by water.8
Chemists developed gelling agents to fine-tune the viscosity of fracking fluids, which helped the wells perform more efficiently. A series of advances since then have made the chemistry and engineering of hydrofracking highly sophisticated.
The high porosity and low permeability of shale makes it a difficult medium to work in. It took years of research by government and industry to develop modern hydrofracking techniques. In the 1970s the federal government initiated the Eastern Gas Shales Project and dozens of pilot hydrofracking projects, and supported public-private research. These efforts were spurred by the energy crisis of 1973, when the Arab members of OPEC, the Organization of Petroleum Exporting Countries, imposed an oil embargo to punish the United States for its support of Israel during the Yom Kippur War.9 It was also spurred by the decline in conventional natural gas production in the United States over the course of that decade. In response to the crisis, the Ford and Carter administrations prioritized the search for new energy supplies. Industry and federal researchers began to focus on techniques to access “unconventional” resources, such as those listed above—coal bed methane, “tight sands” natural gas, and shale gas.
The National Labs—Sandia and Los Alamos in New Mexico, and Lawrence Livermore in California—provided computer modeling, monitoring, and evaluation to demonstration projects. In 1979, the public-private efforts to drive shale gas and coal bed methane to market were formalized in the Department of Energy’s Commercialization Plan for Recovery of Natural Gas from Unconventional Sources. New, three-dimensional microseismic imaging, originally developed by the Sandia Lab for coal mines, was used to locate fractures in shale and “see” unevenly distributed gas formations deep underground. In the meantime, researchers found that diamond-studded drill bits were far more effective at boring through tough shale than conventional drill bits.10
In 1980, a year after the second energy crisis in 1979 caused by the Iranian Revolution, Congress passed the Windfall Profits Tax Act, which created the Section 29 production tax credit for unconventional gas. By providing an incentive of $0.50 per thousand cubic feet of natural gas produced from unconventional resources, the tax credit spurred the growth of shale hydrofracking.11
Most of the early research and demonstration work was conducted in the Devonian and Marcellus Shales, both of which are located on the East Coast. But the key breakthrough happened in the Barnett Shale, in Texas, where a determined tinkerer solved the vexing problem of how to coax gas to flow out of a hydrofracked well smoothly and quickly.
George Phydias Mitchell was the son of a Greek goatherder (Savvas Paraskevopolous, who changed his name to placate an American employer) who became a Galveston-based oil and gas producer. George Mitchell and his brother drilled 10,000 wells around Fort Worth, and became successful at working oil fields others had given up on. In the 1980s Mitchell used government mapping tools and other research to learn how to hydrofrack the Barnett Shale formation. But this shale formation is complex and drillers were stymied by slow, clogged, inefficient wells. Mitchell spent 17 years and $6 million to crack the problem, though many told him he was just wasting his time. It was, says The Economist, “surely the best development money in the history of gas.”12
Having successfully demonstrated multifracture horizontal well drilling, Mitchell Energy engineers had to develop the optimal combination of inputs—water, sand, proppants, chemical lubricants, and so on—to achieve maximum gas recovery at the lowest cost. In 1997, Mitchell Energy developed “slickwater fracturing,” in which chemicals are added to the water pumped into wells to increase the fluid flow. The chemicals, some of which are discussed in the next chapter, had particular functions—friction reducers, biocides, surfactants, and scale inhibitors—to prevent a well from clogging, keep proppants suspended, and accelerate gas pumping. The invention of the slickwater process was the breakthrough that made shale gas economical, and in 1998 Mitchell tapped huge shale gas reserves. The Oil and Gas Journal notes that as a result of Mitchell’s refinements of fracking techniques, a well that produced 70 barrels a day using conventional (vertical) drilling can now produce 700 barrels a day. And a hydrofracture job that once cost $250,000 to $300,000 now cost about $100,000. Passing this milestone, shale gas became a commercially viable resource.13
Mitchell’s technology is now used nationwide, both for gas and for shale oil, which can be extracted from shale beds in the same way gas is. Some wells also produce valuable liquid natural gases (LNG), such as butane and propane. “We can frack safely if we frack sensibly,” Mitchell wrote with Michael Bloomberg in the Wall Street Journal.
Drilling and hydrofracking techniques continue to evolve, and since the 1940s, roughly 1.2 million wells have employed them in the United States.14 By 2009, there were nearly 500,000 active natural gas wells in the United States, double the number in 1990, and the drilling industry reports that about 90 percent of them used hydrofracturing (others say the figure could be as high as 95 or even 99 percent.15)
The Barnett Shale produces over 6 percent of all domestic natural gas.16 In 2001, just before the Section 29 production tax credit expired, George Mitchell sold his company to Devon Energy for $3.5 billion.17 (He died at age 94, in July 2013.)