Let’s begin with the equipment. Roughnecks rely on tall metal drill rigs (such as the rig depicted on the cover of this book) that rise up to four stories tall, which lower diamond-tipped drill bits and sections of steel pipe into the borehole.
Other equipment includes a slurry blender, high-volume fracturing pumps, a monitoring unit, fracturing tanks, proppant storage and handling units, high-pressure treating iron, a chemical additive unit, low-pressure flexible hoses, and gauges and meters to assess flow rate, fluid density, and treating pressure.1
Once a drill pad has been built and the equipment is in place, drillers use a series of choreographed steps to hydrofrack an oil or natural gas well.2 The first step is to drill a vertical borehole into a layer of shale, which typically lies a kilometer (3,280 feet, or 0.62 of a mile) or more beneath the surface.3 This depth can vary widely, depending on the location, geology, stage of drilling, and so on. In the Marcellus Shale, for instance, natural gas wells range from 5,000 to 9,000 feet deep. (By comparison, most residential water wells lie 200 to 500 feet deep.)4
The second step is to reach that depth and turn the drill bit horizontally and continue drilling, extending the lateral borehole up to a mile or two long.
The third step is to line the vertical and horizontal borehole with steel casing, to contain the gas and (so it is hoped) to protect groundwater from pollution, and cement it in place.
The fourth step is to use explosives to perforate holes into the horizontal section of the well casing. This is done by detonating a small package of ball-bearing-like shrapnel with explosives; the shrapnel pierces the pipe with small holes.
The fifth step “completes” the process by using powerful pumps to inject “slickwater” fluids—a slurry (a semiliquid mixture of soluble and insoluble matter) consisting of water, sand, and chemicals—into the wellbore at extremely high pressure (over 9,000 pounds per square inch).5 When the pressurized fluid flows through the perforations at the end of the wellbore, it fractures the shale rock in which gas is trapped in tiny bubbles. As the fluids break open the rock, sand and other “proppants”—materials that hold the fractures open—allow gas to flow out; the chemicals help the natural gas escape the rock and flow up the borehole to the surface.
The sixth step is the “flowback” phase, in which pump pressure is released, allowing much of the fluid in the well to return to the surface.
The seventh step involves cleaning up the borehole and allowing the well to start producing gas. This can take several days.
In preparing a well for production, as many as 25 fracture stages may be used, each of which uses more than 400,000 gallons of water—for a total, in some cases, of over 10 million gallons of water—before a well is fully operational.6
The eighth step is to remediate the wastewater a well produces, which I discuss below.
To answer this, we need to return to the first three steps listed above—the drilling. To hydrofrack a shale rock formation, boreholes are generally drilled straight down some 5,000 to 20,000 feet deep. The average depth is 7,500 feet deep, which is one-and-a-half miles below the surface—equivalent to six Empire State Buildings or more than 25 football fields stacked up end to end.7 (The depth is key to environmental safety, as the industry points out that these wells extend beneath the water table.)
Since the 1990s, hydrofracking has been combined with “directional” drilling, in which a vertical well is drilled thousands of feet deep, whereupon the borehole doglegs and continues horizontally through layers of gas- or oil-bearing shale. In places like the Bakken Formation, in North Dakota, the lateral leg can extend for one or two miles.8
A horizontal well therefore begins as a standard vertical well. A rig will drill thousands of feet down, until the drill bit is perhaps a few hundred feet above the target rock formation. At this point the pipe is pulled from the well, and a hydraulic motor is attached between the bit and the drill pipe, and lowered back down the well. The hydraulic motor is powered by forcing mud (or slurry) down the drill pipe. The mud rotates the drill bit without rotating the entire length of pipe between the bit and the rig, allowing the bit to change direction, from drilling vertically to horizontally.9
Al Granberg/ProPublica
Operators on the surface carefully monitor instruments lowered into the well to monitor the azimuth—the measurement of angle in a spherical context, like the earth—and orientation of the drilling, and steer the drill bit underground.10 Three-dimensional seismic imaging technology has made it easier for drillers to identify “sweet spots,” places where gas has collected in large reservoirs. Once the borehole has been steered into the shale, straight-ahead drilling resumes, moving horizontally through thousands of feet of shale rock.
The combination of directional drilling and hydraulic fracturing works well in places like the Marcellus Shale and Bakken Formation, which were not productive using traditional drilling techniques. From the industry’s perspective, the advantages of directional drilling are many.
First, horizontal drilling allows companies to hit oil or gas reservoirs that are difficult to access, and to stimulate them in ways that simple vertical wells cannot. Some shale reservoirs are located in places where drilling is difficult or not allowed—such as under a school or city. But if drill pads are located on the edge of a city, such as those that ring the Dallas-Fort Worth Airport (DFW), in Texas, and their wells are drilled at an angle that intersects the reservoir, it is feasible—and legal—to tap into it.
Second, horizontal drilling permits the drilling of multiple wells—often six at a time—from a single pad, reducing the cost and environmental impact of energy projects. In 2010, the University of Texas at Arlington made headlines when researchers there ran 22 wells from a single pad to pull natural gas from a 1,100-acre shale formation beneath the campus. (The pad is on state-owned land, and isn’t bound by local municipal rules governing urban gas drilling. Carrizo Oil & Gas operates the wells on university property, which have produced some 110 billion cubic feet of gas).11 But such schemes can be controversial. In 2013, students, citizens, and environmentalists protested the fracking of gas beneath a pristine, biologically rich, 8,000-acre tract of forest land owned by the University of Tennessee in Knoxville.12
Additionally, while horizontal drilling is technically complex, time-consuming, and expensive—a directionally drilled, hydrofracked shale well can cost two or three times as much per foot as a standard vertical well—the wells tend to be more productive than vertical wells, and the extra cost is made up for by bigger gas or oil yields.13 The reason for this is that the size of a well’s “sweet spot” or “pay zone” becomes much larger. A vertical well drilled through a 50-foot thick section of shale will produce a pay zone that is 50 feet wide. If the well turns sideways halfway through the vertical section and runs horizontally for 5,000 feet, then the sweet spot full of gas bubbles will be 5,000 feet long, which greatly increases its productivity.
Horizontal wells can also be safer. In the case of a well blowout—which occurs when pressure-control systems fail, and natural gas is released in an uncontrolled way (blowouts can be explosive and spew fracking fluid into the air and onto the ground)—directional drilling can provide a relief well, which intersects it, allowing rig workers to relieve pressure and control it or seal it.14
Finally, horizontal drilling also has uses other than for hydrofracking. It can be used to install utility lines that cross beneath a city, road, or river, for example.
It is important to note that vertical and horizontal wells are subject to different regulations. In the case of a vertical well, gas is taken from beneath a single piece of surface property. Most states and territories have fairly straightforward mineral rights rules that govern the ownership of gas or oil produced from vertical wells. In the case of horizontal wells, a single borehole can cross beneath numerous pieces of property, perhaps owned by people with differing agendas. In general, the royalties from horizontally drilled wells are established before drilling begins through a combination of government rules and often complex private royalty-sharing agreements. But different states have different laws.
Like most Western states in the United States, for instance, Colorado makes a legal distinction between surface property rights and subsurface mineral rights.15 This distinction is based on Spanish legal precedent (East Coast law, on the other hand, tends to be based on the British precedent.) In Colorado—or North Dakota or Texas—a real-estate transaction may or may not include mineral rights.16 In those states, it is common for the minerals beneath a property to be sold, leased, or retained by previous owners. But there is no law requiring owners to tell buyers about the disposition of mineral rights; there have therefore been many cases in which a buyer did not realize the previous owners had leased the mineral rights to energy companies. In the early days of mineral exploration, this kind of situation reliably led to disputes or even violence.
To obtain the right to drill under private property, an energy firm leases the mineral rights from the federal Bureau of Land Management (BLM).17 If the lease is granted, the company can drill without the surface property owner’s permission. The Colorado Oil and Gas Conservation Commission (COGCC) is responsible for promoting energy development, and tends to favor drillers because they generate revenue for state coffers. Between 2008 and 2019, Colorado estimates it will earn some $2.7 billion from energy extraction. The COGCC also fines drillers for violations of its rules protecting human health and safety: between 1994 to 2000, the Commission collected $1 million in fines from 110 violations.18
But citizens groups worry that fracking will damage homes, harm wildlife, and affect outdoor recreation, and have petitioned the COGCC to stop, or rescind, drilling permits. This type of “resource war” will become increasingly common as the population grows, the climate changes, and the demand for energy pushes fracking into new regions.
Having drilled a directional well, we can turn to what gets injected into them. I’ve mentioned some of the chemicals, as well as the “proppant” that is carried into the shale formation to help release the oil or gas trapped there.
First, acid scours the borehole and the fractures in the rock. Then fluid is injected into the borehole, with the pressure greater than the fracture gradient of the rock. The fluid includes water-soluble gelling agents, such as guar gum, which increase viscosity and help deliver proppant to the bottom of the well.19 As the fracturing proceeds, viscosity-reducing agents—such as oxidizers and enzyme breakers—are added to the fluid to deactivate the gelling agents.
The components of fluid vary, depending on the specifics of the site, but are typically 99 percent water and sand and 0.5 to 1 percent chemicals.20
Drillers usually begin by pumping hydrochloric acid or acetic acid to dissolve rubble, clean the borehole, and reduce pressure on the surface. Then the proppant is added to the fracking fluid and sent down the well. Proppants are small particulates—typically grains of silica sand, resin-coated sand, or man-made ceramic balls—that are used to prop open the fractures in shale rock and keep them open, even after fracking is completed. In essence, proppants make shale artificially permeable.
Drillers use two methods to deliver proppants to the bottom of a well: high rate and high viscosity. High-rate, or slickwater, fracturing causes small spread-out microfractures. High-viscosity fracturing tends to cause large dominant fractures in the rock.
The chemicals in the fluid are tailored to the specific geology of the site, so as to protect the borehole and improve the flow of oil or gas to the surface.21 They include fresh water, salt water, foams, friction reducers, and gelling chemicals. The friction reducer is usually a polymer, which reduces pressure loss caused by friction, allowing pumps on the surface to work at a higher rate without adding greater pressure.
A number of chemicals are used to increase the viscosity of the fracturing fluid, which carries proppant into the formation. But to stop the fluid from pulling proppants out of the formation, a chemical known as a “breaker”—usually an oxidizer or enzyme—is pumped with gel or cross-linked fluids to reduce the viscosity. For a complete list of the chemicals used in hydrofracking, see the appendix at the back of this book.
At the end of fracking, a well is commonly flushed with water, sometimes blended with a friction reducer, under pressure. Some of this wastewater is recovered after fracking and must be carefully disposed of (more on this below).
Water remains by far the largest component of fracking fluid. The initial drilling operation alone may require some 6,000 to 600,000 gallons of fluids.22 According to the EPA, the total volume of water used to hydrofrack a well ranges between 65,000 gallons, such as for shallow coal bed methane production, to 13 million gallons for deep-shale gas production.23 Most wells use between 1.2 and 4 million gallons of fluid, with large projects using up to 5 million gallons (equivalent to the amount of water used by approximately 50,000 people during the course of one day).
Once the hydrofracking fluid has been injected and pressure from the pumps is released, fracturing fluid known as “flowback” surges back up through the borehole to the surface. “Produced water” is fluid that returns to the surface once the well has started producing natural gas or oil. Collectively, flowback and produced water are known as hydrofracking “wastewater,” which is suffused with salts, chemicals, debris scoured from the wellbore, and even naturally occurring radioactive elements.
Because it is contaminated, the question of how to capture, store, and treat millions of gallons of wastewater is a knotty one, and the industry has resorted to several different strategies. In western and southern states, wastewater is often injected back underground into storage wells; when injected into geologically active zones, this has occasionally set off minor tremors.24 Some communities allow wastewater to be spread on roads or fields, for dust suppression or de-icing. Environmentalists worry that the toxins will wash into freshwater and food supplies. In certain cases, wastewater is recycled for use in other wells. In eastern states like Pennsylvania, much of the wastewater is shipped by pipeline or truck to public sewage treatment plants; but those plants are generally not equipped to process the chemicals or the naturally occurring radioactive material that is sometimes dredged up. The improvement of wastewater recycling and disposal methods is a major focus of the industry. (I discuss the concerns about wastewater and earthquakes at greater length in chapter 6.)