Snake Oil: How Fracking's False Promise of Plenty Imperils Our Future

by Richard Heinberg

  Once you know where you want to drill and you have a leasing agreement in hand, you’re ready to get to work. Plan the drilling site—and, if you’re drilling for gas, the pipeline route by which to move your product to market. Send some workers with earth-moving equipment to clear an area for the drilling operations: you’ll need an earthen berm enclosing a football-field-sized site. The drilling rig itself—a 120-foot-high steel structure of platforms surrounding a huge rotary drill—can be rented and assembled from about 60 tractor-trailer-loads of equipment.

  Drilling will probably take two or three weeks, with steel pipe being lowered into the hole as the drill bit chews its way straight down a mile or two, then turns laterally to drill outward another few thousand feet. You’ll cement special steel pipe, called casing, into place in the uppermost parts of the well. This will protect groundwater and stabilize the well for the next stages of the process.

  You’re now ready to slide a device known as a “perforating gun” down to the deepest portion of the well; this sets off small explosive charges that punch holes in the horizontal steel production casing. Once that’s accomplished, it’s necessary to flush the system with diluted acid to unclog the holes.

  Now comes the hydrofracturing stage. Bring in huge pumps on semitrucks, along with four to six hundred tanker loads of water and fracking fluids. With the pumps, first drive a few million gallons of water mixed with “slickening” agents down into the horizontal leg of the casing, forcing the water through the holes to make hairline cracks in the shale. Then add microscopic grains of sand to the water to prop the cracks open.

  After the well is fracked, you will “pump back” water and fracking fluid for several days to open up the well bore so that oil or gas can flow out. You may recapture the fracking fluid for reuse in the next job, or you might decide to put it in an evaporation pond, or send it off to a municipal treatment facility (which is probably poorly equipped to deal with it).

  If you’ve been drilling for gas, you will now cap the well until you’ve constructed a pipeline to connect it with larger transmission pipes. If it’s an oil well, you may be able to start production right away and move the product by truck and rail tanker.

  Now it’s time to drill the next well on your pad; its horizontal leg will point in a different direction from the first well. Once several wells have been drilled and you’ve finished with the pad, simply break down the rented drilling rig so its owner can truck it away to the next site. Most of your work is done.

  As soon as you’ve opened the tap and started production from your new oil or gas well, you will also rehabilitate, as best you can, most of the land around the drilling site, leaving (if it’s a gas well) a fenced area the size of a large living room with several pipes protruding about three feet from the ground, along with a couple of small tanks.

  Figure 15. US Lower 48 States Shale Plays.

  Source: Energy Information Administration, September 2011.

  Along the way, you will have had to move a lot of equipment, water, and chemicals. Altogether, each well will have generated 1,800 to 2,600 18-wheel-truck trips.

  Hiring personnel, renting the drilling rig, paying for the lease, hiring trucks—all of this is expensive. By the time you turn on the tap, you probably will have invested $10 to $20 million in your well pad—which, if you’ve been drilling for gas, may produce only $6 to $15 million worth of product over its lifetime at today’s prices. If it’s an oil well, you are more likely to show a profit, though there’s no guarantee.

  So why does anyone bother? That’s another story—one we’ll explore in Chapter 5.

  THE SHALE GAS BOOM, PLAY BY PLAY

  Meanwhile, let’s continue with our history of the recent and ongoing fracking boom. That history is dotted with the names of the “plays,” or geologic formations, where fracking is common. It takes only a few moments to grasp the essential information about each one.

  As already noted, the boom got its start with the Barnett formation in the 14 counties in and around Dallas and Fort Worth, Texas. In the early 20th century, geologists had identified thick, black, organic-rich shale in an outcrop close to the Barnett Stream, which gave the play its name. But shale is hard and impermeable, so efforts to produce gas in commercial quantities from the formation came to little until the late 1990s. Mitchell Energy began development of the Barnett in 1999; subsequent operators have included Chesapeake, EOG Resources, Gulftex Operating, Devon Energy (which bought out Mitchell), XTO, Range Energy Resources, ConocoPhillips, Quicksilver, and Denbury. The Barnett is now dotted with nearly 15,000 gas wells, which are mostly concentrated in a “core” area of production in and close to Fort Worth, where the shale is thicker and yields more gas per well. Current production is 5.85 billion cubic feet per day, but production rates have hit a plateau since late 2011, despite an ongoing increase in the number of operating wells. (All well and production numbers cited in this chapter are accurate to June 2012.)

  Development of the Fayetteville formation (near Fayetteville, Arkansas) began in 2002 by Southwestern Energy. A surface outcrop of organic-rich shale had been identified before 1930, but once again natural gas extraction efforts were delayed until the arrival of high prices and new technology. After confirming commercial levels of gas in the formation in 2002, Southwestern embarked on a huge and successful concealed leasing operation, securing 455,000 acres in the prime development area prior to drilling its first publicly announced “discovery” well. By late 2004, up to 25 other companies had joined the land-rush, including SEECO, Chesapeake, Petrohawk, XTO, David H. Arrington, and One-Tec (Chesapeake eventually sold its interests in the Fayetteville shale to BHP Billiton Petroleum). The area of production is spread over 25,000 square miles in parts of Cleburne, Conway, Faulkner, Jackson, Johnson, Pope, Van Buren, and White Counties and includes 3,873 wells yielding a total of 2.8 billion cubic feet per day. The recent production trend has been flat despite continued drilling, which suggests that this play is in its late-middle-age phase.

  Figure 16. Distribution and Peak Daily Production of Wells in the Haynesville Shale Gas Play.

  Source: Data from DI Desktop/HPDI, compiled by J. David Hughes, September 2012.

  The Haynesville play, which straddles the Louisiana-Texas border, is named after the town of Haynesville in Claiborne Parish, Louisiana. Chesapeake was first on the scene here in early 2008, followed by Anadarko, Petrohawk, XTO, Exco, EnCana, J-W, EOG, and SWEPI. The leasing rush and subsequent production boom have minted more than a few new millionaires in the Shreveport, Louisiana region. The Haynesville play extends under the core Texas counties of Harrison, Panola, Shelby, and San Augustine, as well as De Soto, Red River, and Caddo Parishes in Louisiana. It has an estimated 250 trillion cubic feet of recoverable gas. In 2010 another rich natural gas reservoir, the Bossier shale, was discovered overlying the Haynesville by six to eight hundred feet. There are currently over 2,800 wells operating in the formations, producing just under 7 billion cubic feet of gas per day, roughly a quarter of all US shale gas being brought to market. While production from the Haynesville formation is the highest of any US shale gas play, it is now declining: this is a fully mature play, though it is only about five years old.

  The Marcellus play underlies a large area of the Appalachian region of the northeastern United States, including the Southern Tier and Finger Lakes regions of New York, northern and western Pennsylvania, eastern Ohio, western Maryland, most of West Virginia, and extreme western Virginia. Altogether, it covers several times more area than the Barnett. It was named for a distinctive organic shale outcrop near the village of Marcellus, New York. Though a few gas wells were drilled a half century ago in Tioga and Broome Counties, New York, these produced only slowly, with a long capital recovery period. Range Resources drilled the first modern hydrofractured, horizontal Marcellus gas well in 2004, setting off a leasing and drilling boom that is still under way. Over 85 companies are currently operating in the Marcellus, including Chesapeake, XTO, Marathon, P
hillips, Chevron, Anadarko, Longfellow, and True Oil. The play currently hosts 3,850 operating wells with current total production of about 5 billion cubic feet per day—a number that could increase substantially as further drilling occurs, and especially if New York State’s fracking moratorium is lifted. The Marcellus is still a youthful play.

  The Utica shale is located a few thousand feet below the Marcellus shale and may have the potential to become a commercial natural gas resource on its own. It is thicker than the Marcellus and more geographically extensive, reaching much of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia, and Virginia, as well as parts of Lake Ontario, Lake Erie, and Ontario, Canada. So far, the only areas of the Utica that have been subject to leasing and drilling are in eastern Ohio and Ontario, Canada, where the formation is closer to the surface and the Marcellus is not present. Wherever the Marcellus formation is present, it is the preferred production target because it is closer to the surface and thus less expensive to drill. Current production from the Utica, from a mere 13 wells, is negligible.

  The Eagle Ford play starts at the Texas-Mexico border in Webb and Maverick Counties and extends 400 miles toward East Texas; it takes its name from the town of Eagle Ford, where the shale outcrops at the surface. The play is 50 miles wide at a depth between 4,000 and 12,000 feet, with an average thickness of 250 feet, and contains both oil and gas. Petrohawk drilled the first Eagle Ford gas well with a horizontal leg and hydraulic fracturing in 2008 in La Salle County, Texas, but dozens of operators are currently active in the play, including Chesapeake, Devon Energy, Lewis, EOG, XTO, Statoil, and Talisman. Current gas production from the Eagle Ford consists of 2.14 billion cubic feet per day from 3,129 wells.

  The Woodford play in Oklahoma saw minor gas production as early as 1939; by late 2004 there were 24 gas wells operating, and by early 2008 that number had grown to more than 750. The largest gas producer from the Woodford is Newfield Exploration; other operators include Devon Energy, Chesapeake, Cimarex, Antero, St. Mary, XTO, Pablo, Petroquest, Continental, and Range Resources. Production from the Woodford shale has peaked and is now in decline, with 1,827 wells currently producing a total of a little over a billion cubic feet of gas per day.

  There are several plays currently producing at a lower rate, such as the Antrim shale in Michigan (9,409 wells yielding 290 million cubic feet per day with a declining trend), as well as formations that may have some future potential but are currently yielding negligible production—including the Caney shale in Oklahoma, the Conesauga and Floyd shales in Alabama, and the Gothic shale in Colorado.

  Outside the United States, shale gas resources in China exceed even those of the United States; potential exists also in South America, Europe, extreme northern and southern Africa, and Australia. However, none of these regions is currently a significant producer. (In Australia, hydrofracturing is used to produce coalbed methane; a major controversy over environmental impacts is erupting there in response.)

  Altogether, in just the last decade the US shale gas industry has drilled over 60,000 wells, with a total current rate of production of about 28 billion cubic feet per day. US shale gas production appears to have peaked or leveled off in late 2011 for reasons we will explore in Chapter 3. The drilling boom has produced roughly 20 trillion cubic feet of gas—over a hundred billion dollars’ worth of product—and has led to the creation of hundreds of thousands of jobs (however temporary) for drillers, truckers, and miscellaneous service personnel. Thousands of households have benefitted financially from lease and royalty payments. Utilities are now burning less coal and more natural gas due to the drilling boom. And makers of US energy policy envision more of the same—cheap, abundant natural gas for as far as the eye can see.

  TIGHT OIL BY THE NUMBERS

  Sometimes the shale rocks that yield natural gas to hydraulic fracturing also (or instead) contain oil. But calling this resource “shale oil” creates confusion because the term is so similar to “oil shale”—a phrase customarily applied to an entirely different resource in the western part of the United States. (We’ll discuss the potential of oil shale in Chapter 6.) In order to avoid this confusion, geologists usually call crude oil that’s present in shale (or similar rock) “tight oil.” Conventional, commercially accessible oil is typically found in porous rock that is topped by an impermeable “cap rock” that keeps the oil from migrating to the surface and oxidizing. But that’s typically not where the oil formed; it migrated there from “source rock,” usually shale, which formed slowly from sediments on ancient seabeds. Tight oil is petroleum that remained in this shale source rock, kept there by unusually tight pore spaces and a lack of pathways between pores. As with shale gas, tight oil presents a challenge for drillers—one that has been partially overcome by the use of new technology.

  Most production of tight oil (sometimes called “light tight oil,” or LTE) in the United States is occurring in two formations—the Bakken play in Montana and North Dakota (also in Saskatchewan, Canada), and the Eagle Ford play in south Texas.

  Figure 17. Distribution and Peak Daily Production of Wells in the Bakken Tight Oil Play.

  Source: Data from DI Desktop/HPDI, compiled by J. David Hughes, September 2012.

  Geologist J. W. Nordquist first described the Bakken formation in the Williston Basin in 1953, following an initial oil discovery at the Clarence Iverson farm in North Dakota in 1951. In 2000, Lyco Energy drilled the first horizontal pilot well into the Bakken; five years later EOG Resources demonstrated that horizontal drilling combined with hydraulic fracturing could recover significant oil from the play. Commercial production using modern fracking technology began in 2008, and by the end of 2010, oil production rates had reached 458,000 barrels per day, outstripping the industry’s capacity to ship oil out of the region.

  Repeatedly throughout the past several decades, geologists have sought to estimate the total oil endowment of the Bakken formation. A 2008 report issued by the North Dakota Department of Mineral Resources suggested that the North Dakota portion of the Bakken contains 167 billion barrels of oil—which, if it represented oil reserves, would put North Dakota ahead of Iraq in terms of oil endowment. However, the percentage of this oil that can practically be extracted is highly debatable, with estimates as low as 1%. Companies operating in the Bakken include Anglo Canadian, Concho, Abraxas, EOG Resources, Continental, Whiting, Marathon, QEP, Brigham, Hess, Samson, and Statoil. As of mid-2012 there were about 4,600 wells producing a total of 570,000 barrels per day. While overall production from the Bakken has grown rapidly in recent years, the Montana portion of the play is already in decline. We will explore the overall potential for this play in the next chapter.

  A New York Times Magazine article (“North Dakota Went Boom” by Chip Brown, January 31, 2013) chronicled the economic and social impact on life in North Dakota as a result of the leasing and drilling frenzy in the Bakken:

  It has minted millionaires, paid off mortgages, created businesses; it has raised rents, stressed roads, vexed planners and overwhelmed schools; it has polluted streams, spoiled fields and boosted crime. It has confounded kids running lemonade stands: 50 cents a cup but your customer has only hundreds in his payday wallet. Oil has financed multimillion-dollar recreation centers and new hospital wings. It has fitted highways with passing lanes and rumble strips. It has forced McDonald’s to offer bonuses and brought job seekers from all over the country—truck drivers, frack hands, pipe fitters, teachers, manicurists, strippers.

  Meanwhile, back in south Texas, the Eagle Ford play has seen substantial production of tight oil as well as shale gas (wells in the southeastern, deeper side of the play yield mainly natural gas while wells on the northwestern, shallower side yield mostly oil). Oil reserves are estimated at 3 billion barrels. Mid-2012 production was 424,000 barrels per day from 3,129 producing wells, with an increasing production trend.

  While the Bakken and Eagle Ford together account for over 80% of current US tight oil production, there a
re other plays that offer varying degrees of promise. The Granite Wash formation, straddling the northern Texas-Oklahoma border, produces roughly 41,000 barrels per day from 3,090 active wells with a rising trend. The Cline shale, located east of Midland, Texas, in the Permian Basin, produces about 30,000 barrels per day from 1,541 wells; here again, production is increasing. Tight oil is also being produced from the Barnett shale in Texas, where 14,871 wells yield only 27,000 barrels per day. In this play the production trend is flat.

  The Niobrara formation in Colorado and Wyoming presents problems with complex geology and access to water, especially given the severe drought that has gripped much of the United States, and Colorado’s recent catastrophic wildfires. Early comparisons with the Bakken have not borne out, and disappointing well results have led Chesapeake to sell off its Colorado leases. Noble, Anadarko, EOG, Quicksilver, and roughly a dozen other mostly small companies are competing in the play, with about 40 active drilling rigs. However, 10,811 operating wells currently yield a mere 51,000 barrels per day of production, and the production trend is flat.

  The Austin Chalk play (which reaches across Texas and into Louisiana) and the Spraberry play (near Midland, Texas) each produce over 17,000 barrels per day.

  The Monterey shale in Kern, Orange, Ventura, Monterey, and Santa Barbara Counties in southern California boasts tight oil resources of up to 15 billion barrels—four times the size of Bakken reserves. But resources are not the same as reserves, and so far production amounts to only 8,580 barrels per day from 675 operating wells, with a flat production trend. This could change if drilling picks up, in view of the Monterey’s very high resource endowment.

  Elsewhere in the world, geology appropriate for the production of tight oil using fracking technology exists in R’Mah formation in Syria, Sargelu formation in the northern Persian Gulf region, Athel formation in Oman, Bazhenov formation and Achimov formation of west Siberia in Russia, Coober Pedy in Australia, and Chicontepec formation in Mexico. Little is yet being done to exploit these resources.