Engineered geothermal systems have wide potential as a renewable energy source Toni Feder Citation: Physics Today 71, 9, 22 (2018); doi: 10.1063/PT.3.4017 View online: https://doi.org/10.1063/PT.3.4017 View Table of Contents: http://physicstoday.scitation.org/toc/pto/71/9 Published by the American Institute of Physics Articles you may be interested in Can carbon capture from air shift the climate change equation? Physics Today 71, 26 (2018); 10.1063/PT.3.4018 Has elegance betrayed physics? Physics Today 71, 57 (2018); 10.1063/PT.3.4022 Rebutting remarks on Feynman and Wheeler Physics Today 71, 12 (2018); 10.1063/PT.3.4009 Coffee stains, cell receptors, and time crystals: Lessons from the old literature Physics Today 71, 32 (2018); 10.1063/PT.3.4019 Homi Bhabha, master builder of nuclear India Physics Today 71, 48 (2018); 10.1063/PT.3.4021 Time crystals in periodically driven systems Physics Today 71, 40 (2018); 10.1063/PT.3.4020 ISSUES & EVENTS Engineered geothermal systems have wide potential as a renewable energy source A test site in Utah will focus on tackling technical barriers. hat will it take to put geothermal energy to use on a large scale? Iceland uses it nearly exclusively for heat and hot water and for about a fifth of its electricity (see related story on page 26). Many countries have geothermal projects. But the vast stores of heat deep beneath Earth’s surface remain largely untapped. “If we can unlock the technologies to make extracting heat in the subsurface technically and commercially viable on a large scale, the promise is huge,” says Bridget Ayling, director of the Great Basin Center for Geothermal Energy at the University of Nevada, Reno. That’s why, she adds, “despite only incremental gains over the last 40 years, the geothermal community continues to pursue engineered geothermal systems,” or EGS, also known as enhanced geothermal systems. In conventional geothermal systems, heat is harvested from hot water in deep CLAY JONES, ENERGY AND GEOSCIENCE INSTITUTE, UNIVERSITY OF UTAH W rocks that have natural permeability. In EGS, by contrast, permeability has to be engineered, usually by injecting cold water into rocks to open existing fractures and create new ones. The water flows through the fractures and absorbs heat from hot rocks before being retrieved. The hot water produced can be used to generate electricity or heat before it is reinjected. With sufficiently deep drilling, the EGS method could be implemented almost anywhere and could be a widespread source of renewable energy. But that requires technical advances, social acceptance, and cost reduction. Aiming to tackle the technical hurdles to realizing EGS, the US Department of Energy in 2014 created the Frontier Observatory for Research in Geothermal Energy (FORGE) initiative. This past June DOE selected the University of Utah from among five candidates as the steward of a dedicated site for that pur- pose. The Utah team, with its EGS site located 300 kilometers south of Salt Lake City, will receive $140 million over five years. In a press release announcing the FORGE award, Secretary of Energy Rick Perry said, “Enhanced geothermal systems are the future of geothermal energy, and critical investments in EGS will help advance American leadership in clean energy innovation. Funding efforts toward the next frontier in geothermal energy technologies will help diversify the United States’ domestic energy portfolio, enhance our energy access, and increase our energy security.” A test laboratory CORE SAMPLES are studied to learn where and how to create fractures for heat reservoirs. This mostly granitic core is about 10 centimeters in diameter. 22 PHYSICS TODAY | SEPTEMBER 2018 A single vertical well, 2297 meters deep, was drilled at the FORGE site last year. With the new award, additional wells will be drilled and fractures will be stimulated to create a reservoir to test and study the full EGS process. That includes looking at fracture predictability, monitoring seismicity, and studying rock characteristics relating to permeability, geochemistry, and more. About half the FORGE funding will go toward drilling, infrastructure, and seismic and other maintenance. The rest RICK ALLIS, UTAH GEOLOGICAL SURVEY THIS UTAH SITE was selected by the Department of Energy for dedicated research on enhanced geothermal systems. The rig in the distance was used to drill a vertical well for preliminary scientific measurements. The site, about 300 kilometers south of Salt Lake City, is collocated with solar and wind-energy production. will be awarded for R&D through peerreviewed competitions to be overseen by the Utah team. In the US, EGS projects have often piggybacked on conventional geothermal sites that were already producing electricity. “The plant operators don’t want their production to be negatively impacted. That can be scientifically limiting,” Ayling says. “FORGE is fairly unique in that it is independent. The best domestic and international researchers can test and develop innovative, cuttingedge, subsurface technologies. I am hopeful that this will give us the opportunity to be bold and brave and to try things that, so far, we have not been able to try.” Creating a reservoir where injected water can be heated is among the toughest challenges in EGS. “We want to create permeability by opening the existing fractures,” explains FORGE principal investigator Joseph Moore. “That’s why one emphasis is on understanding the stress field in the rocks.” For adequate heat exchange, an EGS reservoir requires a large network of small fractures, a millimeter wide or less. “You need an effective radiator for water to percolate and circulate through,” says Moore. “You have to avoid short circuiting,” in which the water flows out, via a dominant fracture, too fast to be adequately warmed. To maximize well productivity, the researchers want to create multiple fracture networks in a single reservoir, which can be several kilometers across. One area of intensive research is isolation—stopping fractures from forming at a given part of a borehole and then stimulating them at successively deeper locations. The stopping can be done, for example, with a fibrous material that is solid when injected and breaks down and becomes soluble at high temperatures, says Susan Petty, whose Seattlebased company AltaRock Energy holds the patent for that method of isolation. (See also the interview with her at http://physicstoday.org/petty.) The EGS community is increasingly embracing horizontal drilling, an approach adopted from the oil and gas industry. (See the articles in PHYSICS TODAY by Michael Marder, Tadeusz Patzek, and Scott Tinker, July 2016, page 46, and by Brian Clark and Robert Kleinberg, April 2002, page 48.) Fractures often form vertically, so a reservoir with wellbores approaching horizontal—perpendicular to the fractures—could be effective, says John McLennan, a FORGE coprincipal investigator. Drilling a deviated well at great depth is tricky, and the change in inclination needs to be gradual to accommodate the well casing, steel insertions that maintain the well’s integrity. So far, geothermal wells up to about 40° from vertical are common, but McLennan and others hope to get closer to horizontal. “It opens up new opportunities for success,” he says. Another focus is understanding how the rocks interact with the injected water. Will clays or other minerals form that eventually block flow pathways? Will cold injected water shrink the rocks so the fractures widen? Ayling’s specialty is reservoir characterization, including fluid chemistry, hydrothermal alterations, and physical properties such as rock strength and permeability. For EGS, she says, it’s important to evaluate the probable rock types and conditions before deep drilling. “We still don’t know what the best sites are for developing large-scale EGS. It’s a knowledge gap.” To get to useful temperatures—the DOE’s goal is 175 °C to 225 °C—requires going several kilometers deep, into hard SEPTEMBER 2018 | PHYSICS TODAY 23 BRIDGET AYLING ISSUES & EVENTS THE NOW-DECOMMISSIONED HABANERO PILOT PLANT in South Australia’s Cooper Basin produced geothermal power under conditions of extreme heat and pressure. The U-shaped loops allow the pipes to withstand thermal expansion and contraction when hot geothermal fluids flow through, a design that prevents damage to the wellhead. Heat exchangers and cooling towers are visible in the background. rocks. Drill bits wear faster in those environments than in shallower shales and other sedimentary rocks encountered by the oil and gas industry. Electronics and other materials for characterization and ongoing monitoring have to withstand higher temperatures. So while tools and know-how are transferable from the oil and gas industry, the EGS approach also requires different—and sometimes innovative—instruments. “There are materials from the nuclear industry that survive high temperatures,” notes Petty. “But we haven’t yet applied them in drilling.” Australia’s Habanero site gave (see photo above) the EGS community experience working at great depth, high temperatures, and at very high pressures. During a five-month test run in 2013 that produced 1 MW of electrical energy, Ayling injected chemical tracers there. “Tracer testing is one of the few direct methods where you can definitively prove your wells are connected,” she says. “You can also calculate your average fluid-flow velocity along with other reservoir parameters.” The Habanero project “was expensive, but it proved EGS could be done under extremely 24 PHYSICS TODAY | SEPTEMBER 2018 challenging conditions.” The economics of scaling up to a larger 50 MW power plant did not stack up, she adds, and the site was decommissioned in 2016. “The ability to create multiple-fracture sites is still a challenge,” says McLennan. So are steering the drill bits, cutting costs by drilling faster, working underground at high temperatures, and making sure subsequent wells intersect the engineered fractures optimally to retrieve the heated water. “That is the purpose of FORGE—to provide a test laboratory.” Seismicity risk and social acceptance Studies on EGS go back to the late 1970s, when Los Alamos National Laboratory first looked into harvesting energy from hot, dry rocks. Budget cuts ended that project around 1990, but a smattering of efforts carried on around the globe. Two EGS plants in the Alsace region of France produce energy commercially: Soultz-sous-Forêts, which began as a scientific project, has since 1986 produced about 1.7 MW of electricity for the French grid. And 10 kilometers away, a plant in Rittershoffen produces 24 MW of thermal energy from hightemperature geothermal water. Besides technical and financial challenges, seismicity can also derail EGS. In Basel, Switzerland, for example, a project was shuttered about a decade ago after a magnitude 3.4 earthquake, attributed by some to EGS, damaged buildings. And last fall a magnitude 5.5 earthquake, which was followed by a smaller tremor, put a halt to an EGS project in South Korea. In that case, says Ernest Majer of Lawrence Berkeley National Laboratory, it’s not clear that the EGS project caused the earthquakes, but the earthquakes definitely cast a shadow over international EGS efforts. Some seismicity is unavoidable during the creation of an EGS reservoir. But Lauren Boyd, EGS program manager at DOE, notes that unlike fracking in the oil and gas industry, which involves injecting more liquid than is removed, the water injected in EGS is taken out and reinjected in a closed loop, which reduces the seismicity risk. Brian Carey, an engineer at GNS Science’s Wairakei Research Centre in Taupo, New Zealand, and the International Energy Agency’s executive secretary for geothermal technical collaboration, stresses that the sustainability of EGS depends on community acceptance. “That is probably one of the most significant aspects.” Turn on the heat Interest in EGS in the US and elsewhere was rekindled by a 2006 study, The Future of Geothermal Energy: Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21st Century. Commissioned by DOE and written by an MIT-led interdisciplinary panel, the report estimated total US EGS resources of 13 million exajoules in crystalline rock formations at depths of 3 km to 10 km. That’s roughly equivalent to the energy in 2 quadrillion barrels of oil, according to study chair Jefferson Tester, now at Cornell University. Extracting a small fraction could satisfy “a major portion of the US’s primary energy needs,” he says. Tester says the 18-member panel was restricted to electricity in its consideration of EGS. But EGS has more to offer. “We lose about 90% of its energy value by converting the geothermal heat to electricity instead of using the heat directly,” he says. Other factors are also converging to raise hopes for EGS. Science has advanced in recent years: The geophysics and geochemistry of the subsurface are better understood, numerical modeling is more accurate, and new tools and know-how from the oil and gas industry can be applied. At a time when climate change is recognized as among the greatest threats to the planet, the prospect of low carbon emissions enhances the approach’s appeal. And EGS could be a steady source to complement the fluctuating power supplied by the wind and Sun. Peter Meier, CEO of Geo-Energie Suisse, notes that in Switzerland, “We have no sea, and therefore not a lot of wind. Solar is not enough, and hydropower is almost to capacity.” Last year the country decided to phase out its nuclear reactors. “That is why we are motivated to do EGS,” he says. If it works, his company predicts that injection–production well pairs could provide up to 5 MW of electricity from the local rock conditions. The company is reassessing the project’s seismicity risk and hopes to get the green light to start construction late next year or in early 2020. One key attraction of EGS is its wide applicability. Conventional geothermal energy relies on natural convective flow. For the US, that’s in the western states. SEPTEMBER 2018 | PHYSICS TODAY 25 “Successful EGS will extend the geographical applicability to other parts of the country,” says McLennan. “In many parts of the country, you can find heat, but you don’t have water or fractures. EGS adds both.” Take the Northeast, says Tester. “Imagine using EGS to take heat out of ground and use it for heating homes.” That, of course, would require distribution systems. “You have to be reasonably close to the source—transporting hot water or steam long distances is technically possible but not economically attractive.” The country needs to transform its infrastructure in any case, says Tester, so why not be creative. “A lot of geothermal failures have been because of a lack of continuity in support and patience.” The capital investment in EGS is high, but systems should be designed to work for at least two decades. And, he adds, if the US doesn’t pursue EGS seriously, “we are going to fall behind the rest of the world.” Toni Feder Low Noise Preamplifiers Voltage Preamplifier • 1 MHz bandwidth • 4 nV/√Hz input noise • 100 M Ω input impedance • Gain from 1 to 50,000 • RS-232 interface • $2595 (U.S. list) SR560 Low-Noise Voltage Preamplifier The SR560 offers a true-differential (or single ended) front-end, configurable high/low pass filtering, and rechargeable batteries that provide up 15 hours of line-free operation. With a microprocessor that ‘sleeps’, no digital noise will contaminate your low-level analog signals. Current Preamplifier • 1 MHz bandwidth • 5 fA/√Hz input noise • 1 pA/V maximum gain • Adjustable DC bias voltage • Line or battery operation • $2595 (U.S. list) SR570 Low-Noise Current Preamplifier The SR570 offers current gain up to 1 pA/V, configurable high/low pass filtering, and input offset current control. It can be powered from the AC line or its built-in batteries, and is programmable over RS-232. You can set the SR570 for highbandwidth, low-noise, and low-drift gain modes. Stanford Research Systems 408-744-9040 www.thinkSRS.com · Physics Today Drilling to Earth’s mantle Susumu Umino, Kenneth Nealson, and Bernard Wood Citation: Physics Today 66(8), 36 (2013); doi: 10.1063/PT.3.2082 View online: http://dx.doi.org/10.1063/PT.3.2082 View Table of Contents: http://scitation.aip.org/content/aip/magazine/physicstoday/66/8?ver=pdfcov Published by the AIP Publishing This article is copyrighted as indicated in the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 130.156.1.80 On: Sat, 17 Oct 2015 18:44:29 Drilling to Earth’s mantle Susumu Umino, Kenneth Nealson, and Bernard Wood Half a century after the first efforts to drill through oceanic crust failed, geoscientists are ready to try again. Susumu Umino is a petrologist at Kanazawa University in Japan, Ken Nealson is a microbiologist at the University of Southern California in Los Angeles, and Bernard Wood is a geochemist at the University of Oxford in the UK. All are research professors. JAMSTEC I n 1909, Croatian seismologist Andrija Mohorovičić made a bold prediction—that Earth consists of distinct layers of rock above its core. On analyzing an earthquake that had struck earlier that year, he noticed that seismic waves below a depth of about 56 km travel a few kilometers per second faster than those above that depth. The abrupt change in speed marks what is now known as the Mohorovičić discontinuity, or Moho—the boundary between Earth’s crust and upper mantle, where a fundamental change in the rocks’ composition is thought to occur. Below the continents, the Moho’s depth can vary from 25 km to 60 km. But underneath the oceans the crust is much thinner, and the Moho lies tantalizingly close to the sea floor— typically just 6 km below it. In 1957 a group of American geoscientists led by Harry Hess, a founder of the theory of plate tectonics, proposed an ocean drilling program dubbed Project Mohole designed to sample a section of crust and shallow mantle to understand its composition, structure, and evolution. Four years later, between March and April 1961, the team successfully recovered a 14-m-long core of hard, oceanic crust, or “basement,” off the coast of Guadalupe, Mexico, below 3600 m of water and 170 m of sediment.1 That demonstration, though, was the extent of the original project’s achievement. Ocean drilling for petroleum was in its infancy at the time. Dynamic positioning, a technology to stabilize the position of a ship during the drilling process, didn’t yet exist, and Project Mohole lost its funding in 1966. The Apollo program, begun almost the same time as Mohole, recovered lunar samples within a decade, yet despite a half century of undersea drilling, no one has yet managed to reach the Moho. Nonetheless, Project Mohole led to the establishment of an international collaboration in scientific ocean drilling that has continued for decades. The collaboration is currently known as the Integrated Ocean Drilling Program (IODP); after October 2013 it will be known as the International Ocean Discovery Program. And with the recent development of the Japanese vessel Chikyu, briefly described in box 1, the aspirations of generations of Earth scientists to drill completely through the oceanic crust, through the Moho, and into the upper mantle are now technically feasible. In April 2012 IODP endorsed a plan that makes mantle drilling a high-priority goal for the next decade.2 Surveys of the three most promising drilling sites (see box 2) are now underway. Mohole to mantle Much of the crust–mantle dynamics is understood. The thin rocky ocean crust that covers almost twothirds of Earth’s surface forms out of magma, par- This article copyrighted as indicated the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 36 is August 2013 PhysicsinToday www.physicstoday.org 130.156.1.80 On: Sat, 17 Oct 2015 18:44:29 tially melted mantle rock extruded at the mid-ocean ridge, the world’s longest volcanic chain. Along that chain, which wraps around the planet like the seam of a baseball for more than 65 000 km, the tectonic plates are continually renewed by the solidified magma as they gradually move apart. The rate at which they spread depends on a plate’s location and varies from less than 1 cm/yr to as much as 17 cm/yr. Although only a fifth of the plates in today’s midocean ridge spread quickly—at more than 8 cm/yr— more than half of today’s sea floor, and the great majority of crust subducted back into the mantle during the past 200 million years, was produced at those fast-spreading parts of the ridge. As a plate moves away from the ridge, it cools predictably with age, as outlined in figure 1. In addition, seawater enters the crust and uppermost mantle through deep fractures, where it is heated and becomes a reactive fluid that hydrates surrounding rock and exchanges materials with it before returning to the ocean. While chemically altered by the fluid, the crust and uppermost mantle may also become a habitat for microorganisms. Elsewhere, subducting plates drag seawater into the mantle, where the water reduces rock viscosity and melting temperature (see the article by Marc Hirschmann and David Kohlstedt in PHYSICS TODAY, March 2012, page 40). Like water, carbon is an essential material for life, and both play critical roles in Earth’s environment. But our knowledge of the contribution of the mantle, the largest reservoir of both components, to the global water and carbon budgets remains totally unconstrained in the absence of representative samples. “Representative” is the operative word. Indeed, one can argue that samples from Earth’s mantle are not rare. But they reach the surface heavily altered from their original, pristine state underground. Pieces of mantle may be entrained in the upward flow of buoyant magma and brought to the surface during volcanic eruptions or spliced into the continental crust during the collisions of continents. Those mantle rocks may have lost part of their original composition through melting. They may have become part of tectonically uplifted outcroppings that now lie exposed on the sea floor or one of Earth’s continents; extremely large sections of displaced crust and mantle known as ophiolite exist in a few places around the world and are heavily studied, partly because they’re so easily accessible. Those slices through ancient Moho are thought to preserve a record of the melting and crystallization process similar to what occurs at the mid-ocean ridge (see PHYSICS TODAY, January 2005, page 21), but because of their violent history, no one knows where or how deep underground they came from. A few kilograms of fresh mantle from beneath an intact, tectonically quiet region of oceanic crust would provide a wealth of new information, comparable to the treasure trove obtained from the Apollo lunar samples, on Earth’s dynamics and evolution. That’s a central motivation driving the new Mohole to the Mantle (M2M) project. Because of the relatively uniform architecture of fast-spreading plates, understanding the genesis Box 1. The challenge and the Chikyu The deepest hole ever drilled, on the Kola Peninsula in Russia, reaches 12.3 km underground. But under the sea floor, a more challenging environment in which to drill, few holes exceed a kilometer; to date, the record is 2.1 km at the Integrated Ocean Drilling Program (IODP) site 504. The technology required to go deeper is feasible. A hole more than a few kilometers deep tends to collapse during drilling, under the huge load from Earth’s crust around it; the pressure difference between crustal rock and the water column on a hole 3 km deep is 45 MPa. To prevent or forestall the collapse, engineers circulate drilling mud through what’s known as a riser system that connects the borehole with an onboard pump. One steel outer pipe surrounds an inner one, the drill “string” through which a “core” is recovered. The mud and drill shavings are pumped up to the ship in the space between the two pipes. With a density between seawater and the rock surrounding the hole, the circulating mud reinforces the walls of the hole and acts as a lubricating fluid. The deep-sea drilling vessel Chikyu (“Earth” in Japanese), shown here, was designed to reach down to about 7.5 km under the sea floor and was launched in 2002. Although it’s currently equipped with a riser system that can operate at ocean depths of 2.5 km, work is under way to develop the technology required to drill in ocean depths exceeding 4 km, where the crust is coolest. (For more on IODP’s drilling activities, see the report on page 22.) Other aspects of the project also require further engineering. Strategies are needed for coring and logging rock samples at temperatures near 250 °C, the hottest temperature at which drilling equipment remains durable (coring refers to retrieving the cylindrical rock samples, and logging refers to the recording of information, both as drilling proceeds and after the core has been retrieved). Drill bits that can effectively cut hard, abrasive, hot rock at the end of high-tensile-strength drill strings will also be essential. So will low-weight drilling mud, casing, and cementing materials that work in hot conditions. When sampling the rock retrieved from the Moho, researchers will no doubt be confronted with unprecedented challenges, such as precisely discerning what distinguishes living and dead cells in anaerobic, high-pressure, high-temperature regions and discriminating microflora from contaminants. Both require creative and innovative solutions. This article www.physicstoday.org is copyrighted as indicated in the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded August 2013 Physics Today 37 to IP: 130.156.1.80 On: Sat, 17 Oct 2015 18:44:29 Earth’s mantle Box 2. Drilling site selection LATITUDE Ideally, researchers would prefer to drill in the shallowest water Original Project Mohole 30° that overlies the coldest oceanic crust. But those are conflicting requirements: In shallow water, 20° North Arch of Hawaii close to the mid-ocean ridge, the crust is young and hot; farODP site 1256 10° ther from the ridge, it’s older and colder, but under deep water (see figure 1). Prospective 0° drilling sites for the Mohole to −80° −160° −150° −140° −130° −120° −110° −100° −90° the Mantle Project are limited to LONGITUDE three candidates, all in the Pacific Ocean: the original late−7000 −6000 −5000 −4000 −3000 −2000 −1000 0 1950s drilling site off the coast WATER DEPTH (m) of southern California; Ocean Drilling Program (ODP) site 1256 on the Cocos plate off the coast of Mexico; and a site just north of Hawaii. Crust that is older than 20 million years should meet the temperature requirement, with crust cooler than about 250 °C at Mohorovičić-discontinuity depths. The area on the Cocos plate is advantageous in that it sits in the shallowest water and over the thinnest crust. But that crust is also warmer than 250 °C at the Moho; major obstacles posed by the high temperature include thermal shock on the rock to be drilled and the durability of logging tools. The Baja site contains older crust, 25 million to 35 million years old, and is cooler than 250 °C at the Moho, but that site lacks modern seismic data needed to evaluate Moho characteristics. Finally, the site off Hawaii is oldest and thus coldest, but it’s also in the deepest water. In addition, the influence of arc volcanism and the Hawaiian plume on the crust and mantle there remains uncertain (see the article by Eugene Humphreys and Brandon Schmandt, PHYSICS TODAY, August 2011, page 34). and evolution of crust and mantle at one site can be extrapolated with some confidence to much of Earth’s surface. Earth scientists have well-developed theoretical models of ways in which magma accretes along ridges and becomes crystallized rock, and such models can be tested using samples recovered from cored sections of ocean basement. Besides testing the models of crustal accretion and melt movement, the drilled cores will be used to resolve the geometry and intensity of the circulation of hot water in underground fractures and subduction zones and to document the limits and activities of the deep microbial biosphere. After the hole is drilled, the several-kilometer-long tube of crust and mantle removed, and the painstaking process of logging the data completed, the hole will be used for additional experiments. Sensors and other subsea equipment will be installed in the borehole to monitor physical stresses, fluid movement, temperature, and pressure. The mantle’s makeup Earth comprises distinct chemical reservoirs. The deepest is the core, which, constituting just under a third of the planet’s mass, is metallic and thought to consist mostly of iron. Above it resides the voluminous mantle, which contains some two-thirds of Earth’s mass in three principal layers of rocky, silicate materials. The overlying continental and oceanic crusts, by comparison, contain less than 1% of Earth’s mass and are themselves composed of solidified magma. A better grasp of the mantle’s composition would enable researchers to place better constraints on melting processes. It would also help determine the nature of Earth’s asteroidal building blocks and the time scales and physical conditions at which they accreted to form the planet. Current estimates of the chemical composition of the silicate part of Earth come from mantle samples delivered to the surface. Those “peridotites,” which contain about 75% olivine [(Mg, Fe)2SiO4] and lesser amounts of other silicates and oxides, vary in composition by virtue of being tectonically altered, partially melted, or possibly infiltrated with melt from other types of rock. Mantle peridotite typically begins to melt at about 1300 °C and is completely molten by 1700 °C, depending on pressure. At mid-ocean ridges, about 15% of the mantle melts and produces the volcanic rocks of the ocean floor. The residual mantle left behind is depleted of “incompatible” elements— those elements in the rock that melt most easily. It’s long been recognized that silicate Earth’s composition can be approximated as some combination of residual peridotite and the silicate melts that form crustal rock.3 Ocean drilling offers a way to improve our understanding of the relationship between those two components. Currently, the best estimate of “primitive” unmelted mantle comes from peridotites that show the least evidence of having undergone partial melting.4 Such mantle pieces and others whose unmelted compositions are theoretically reconstructed appear to contain certain elements in identical abundance ratios to so-called chondritic meteorites and the Sun. The elements of concern are the lithophilic (rock-loving) elements such as calcium, aluminum, This article copyrighted as indicated the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 38 is August 2013 PhysicsinToday www.physicstoday.org 130.156.1.80 On: Sat, 17 Oct 2015 18:44:29 Meaning of the Moho Because the vast majority of Earth’s deep interior is inaccessible by direct sampling, our understanding of its layered structure is indirect, based largely on seismic models that are calibrated using hightemperature and high-pressure experiments on mantle-borne materials. Fast-spreading oceanic crust is seismically divided into three layers, shown in figure 2, each of which varies in the speed Vp at which compressional Layer 1 4 VP (km/s) 8 6 Layer 2 0 DEPTH BELOW SEA FLOOR (km) titanium, uranium, and scandium, which remain concentrated in the silicate part of Earth. By contrast, the mantle is depleted in siderophilic (ironloving) elements such as nickel, cobalt, platinum, and gold, which were swept into the core as the planet differentiated. A direct demonstration that the mantle contains precisely chondritic ratios of some elements and deviates from that model ratio in others is likely to have powerful implications for our understanding of planetary accretion and differentiation and the timing of those events in Earth’s geological history. (See the article by Bernard Wood, PHYSICS TODAY, December 2011, page 40.) Currently geologists have no viable alternative to the chondritic-Earth assumption. But in 2006, Maud Boyet and Richard Carlson suggested that the assumption breaks down, at least in the case of the samarium–neodymium abundance ratio in the primitive mantle.5 Their thesis, it’s been argued,6 may indicate that an early formed crust was lost to space by the bombardment of meteors early in Earth’s history. If our current chondritic-ratio models are crude and wrong in detail, a central question becomes, Exactly how wrong? Pristine samples recovered by ocean drilling should help answer that question. A −6 100° C B C −8 300 °C 10 20 30 200° 50 40 60 AGE (106 years) C 70 80 90 100 Figure 1. Oceanic crust forms at the mid-ocean ridge and slowly cools as it ages and moves away from the ridge. A simple thermal diffusion model predicts the temperature of the crust and upper mantle as a function of age and depth below the sea floor. Applying appropriate boundary conditions—a thermal diffusivity of 6 × 10−7 m2 s−1, an initial mantle melting temperature of 1340 °C, and a sea-floor temperature of 0 °C—yields the isotherms shown in the plot. The orange bars indicate the approximate temperature at each of the prospective drilling regions—A (the Cocos plate), B (off Baja, California), and C (off Hawaii), discussed in box 2—near the presumed Mohorovičić-discontinuity depth of 6 km. waves propagate through it. Seismic waves travel at less than 3 km/s through the top layer, which is commonly interpreted as fine-grained sediment. In the second and third layers, respectively, the wave speed increases up to 6.7 km/s and then levels off around 7 km/s. In those two layers, the waves pass from lavas and sheeted dikes—essentially vertical intrusions of solidified magma, or basalt—and into “gabbro,” a coarse-grained and crystalline form of basalt rich in low-density aluminum. Previous drilling expeditions to the hole dubbed 1256D, at one of the prospective sites for the M2M project (see box 2), have reached more than 1.5 km 0 1 1256D 504B 4 5 6 DEPTH (km) 3 Moho −4 −10 2 Layer 3 −2 Oceanic crust Continental crust Lithosphere Partial melting 7 8 9 Figure 2. When a seismic wave encounters an interface between materials with different acoustic impedances, some of the wave’s energy is reflected. At left, a seismic reflection image shows the layered structure of crust beneath the Pacific Ocean. At its right are compression-wave velocity profiles Vp of the seismic waves propagating through the layers, with zero depth referenced to the bottom of the first, sedimentary layer. The sharp, strong reflection below the third layer marks the Mohorovičić discontinuity, or Moho, the boundary between Earth’s crust and its lithosphere, or upper mantle. In the plot, the gray region outlines the range of seismic velocity profiles measured through 29-million-year-old crust of partially melted mantle rock extruded from Earth’s mid-ocean ridge. The green and red profiles are the estimated wave velocities around holes at drilling sites 1256 (described in box 2) and 504 from ocean-bottom seismometers. (Data from ref. 9; image courtesy of Christopher Smith-Duque.) This article www.physicstoday.org is copyrighted as indicated in the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded August 2013 Physics Today 39 to IP: 130.156.1.80 On: Sat, 17 Oct 2015 18:44:29 Earth’s mantle below the Pacific Ocean floor, through the first two layers.7 Of the more than 2000 exploratory holes dug to date, that hole is also the only one that reaches the boundary between the sheeted dikes and gabbro.8 (Another hole, dubbed 504B, at 2.1 km the deepest oceanic hole ever made, remains too shallow for that transition because of the greater crustal thickness where it’s located.) Judging from recovered samples, the seismic velocity gradient occurs in the sheeted dikes and appears to be caused by changes in the density of cracks they contain rather than changes in rock type or grain size. Just below the third layer is the Moho, marked by a sharp velocity transition from about 7 km/s to 8 km/s that occurs within 500 m. It is the outermost seismic boundary separating crust and mantle, and its geological meaning will remain a matter of conjecture until core samples are collected. But because the seismic transition is sharp, the discontinuity is thought to represent the geological contact between gabbro and the peridotites, which are more dense, being rich in magnesium and poor in aluminum. In other places the Moho may be a more diffuse, complex transition zone with numerous seismic reflecting layers,9 as seen in parts of the Oman ophiolite.10 Recent seismic data in the western Pacific reveal a particularly high compression-wave velocity ABOVE SEA FLOOR (m) 1000 100 10 BELOW SEA FLOOR (m) 0 −10 −100 −1000 102 104 106 108 1010 CELL CONCENTRATION (count/cm3) 1012 Figure 3. Microbial cells, whose number is determined by fluorescent imaging, decrease in concentration with depth in sea-floor sediment. Open circles represent cells found below the South Pacific Gyre, where cell numbers are very low even at the sea-floor surface thanks to the nutrient-poor nature of the gyre. Open triangles represent cells found at the edges of the gyre, where more organic-compound-enriched sediments exist on the sea floor; filled circles represent cells found in sediments elsewhere on the Pacific sea floor. The cellular concentration decreases roughly linearly to very low levels—about a factor of 10 or more for each order of magnitude increase in depth below the sediment surface. (Adapted from ref. 11.) of 8.6 km/s and strong anisotropy with respect to direction of the waves immediately below sharply imaged Moho. Those data, from Shuichi Kodaira (Japan Agency for Marine-Earth Science and Technology) and colleagues, seem to suggest that the reflectors sit in a preferred orientation relative to the mid-ocean ridge axis; that orientation is produced by inhomogeneous stresses or shearing. The orientation could be detected in drill cores and would help answer a fundamental question in geodynamics: whether the upwelling path of hot deep mantle material is best modeled as a passive, plate-driven flow or an active, buoyancy-driven flow. A biological perspective To a biologist, the M2M project presents several interesting issues: defining the limits of life, identifying signatures of present or past life, and learning what new types of metabolism may be required for organisms to grow and survive. Let’s take each issue in turn. The limits of life. What are the extremes of temperature, pressure, and nutrient depletion to which earthly life can adapt? As one proceeds downward from sea-floor sediment toward the Moho, when do the conditions become so extreme that life is no longer detectable in recovered drill-core samples? Current evidence from a number of different laboratories indicates that microbial life, as tough as it is, disappears rather rapidly with sediment depth:11 Few recognizable biological cells remain intact at depths of 2 km or more below the sea floor. (For a 2009 plot of the available data, see figure 3.) Evidence from nearly 40 years of studying thermophilic microbes indicates that they are capable of growth up to about 115 °C, a temperature that corresponds to depths of 4 km to 5 km below the sea floor.12 Temperatures at which cellular life could survive may be much hotter than that, though. Fifty years ago no one would have believed that life could survive, let alone thrive, at 100 °C, the temperature of many thermophile communities along the edges of hot vents in the deep ocean. What’s more, although details provided by drill-core samples cannot help but be specific to Earth’s crust, the findings may shed light on life-detection missions on other planets or other extreme environments on Earth. The search for biomolecules. Retrieved samples should offer ample information about conditions in which biomolecules, both organic and inorganic, survive or are destroyed past the point of recognition. Life is surprisingly resilient, and ways that it or its chemistry survives extreme conditions belowground will be of great interest. That may be especially true for inorganic metal isotopes—one of our best tools for the study of ancient life—which may offer new clues to early life far below where organic molecules are stable. New types of metabolism. What kinds of energy sources, both organic and inorganic, are available in deep sediment and crust? It’s generally thought that subsurface metabolism is predominantly lithotrophic—powered by inorganic energy sources, typically hydrogen in the subsurface (for a discussion, see reference 13). Actually, almost any chemical capable of serving as a source of electrons This article copyrighted as indicated the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 40 is August 2013 PhysicsinToday www.physicstoday.org 130.156.1.80 On: Sat, 17 Oct 2015 18:44:29 can, in principle, be used by life, and thus may have somehow influenced or driven the origin and evolution of life. And understanding where deep subsurface biota reside should provide insight into where some of the earliest life on our planet may have been harbored. As with the search for life beyond Earth, one can’t be sure that life in the deep unknown will conform to our definition of life at the surface, but it should prove fascinating to ply socalled non-Earth-centric methods that can detect life even if it turns out to be fundamentally different from forms with which we’re familiar.14 Almost nothing can be said with certainty other than at some depth belowground, conditions become so severe that carbon–carbon bonds become unstable and life as we know it disappears. And although it’s not clear what will be learned, we’ll almost certainly gain a new appreciation of many aspects of life above the surface through an analysis of what’s below it. The optimism of Harry Hess is worth applying to the M2M project more generally. As he said at a US National Academy of Sciences meeting in 1958: Perhaps it is true that we won’t find out as much about the Earth’s interior from one hole as we hope. To those who raise that objection I say, If there is not a first hole, there cannot be a second or a tenth or a hundredth hole. We must make a beginning. Fortunately, because of the petroleum industry’s efforts to mine oil offshore, there exist a well-established infrastructure and history of hole drilling. The scientific quest is to go deeper and bring up what will hopefully be treasure troves. References 1. For a personal account, see J. Steinbeck, Life, 14 April 1961, p. 110. 2. M. Bickle et al., Illuminating Earth’s Past, Present, and Future: The Science Plan for the International Ocean Discovery Program 2013–2023, Integrated Ocean Drilling Program Management International, Washington, DC (2011). 3. A. E. Ringwood, Geochim. Cosmochim. Acta 15, 257 (1959). 4. S. R. Hart, A. Zindler, Chem. Geol. 57, 247 (1986); W. F. McDonough, S. S. Sun, Chem. Geol. 120, 223 (1995). 5. M. Boyet, R. W. Carlson, Earth Planet. Sci. Lett. 250, 254 (2006). 6. I. H. Campbell, H. St. C. O’Neill, Nature 483, 553 (2012). 7. D. A. H. Teagle et al., Proc. Integrated Ocean Drilling Program, vol. 335, IODP Management International, Tokyo (2012). 8. D. S. Wilson et al., Science 312, 1016 (2006). 9. M. R. Nedimović et al., Nature 436, 1149 (2005). 10. N. Akizawa, S. Arai, A. Tamura, Contrib. Mineral. Petrol. 164, 601 (2012). 11. S. D’Hondt et al., Proc. Natl. Acad. Sci. USA 106, 11651 (2009). 12. M. T. Madigan et al., Brock Biology of Microorganisms, 13th ed., Benjamin Cummings, San Francisco (2012). 13. K. J. Edwards, K. Becker, F. Colwell, Annu. Rev. Earth Planet. Sci. 40, 551 (2012). 14. P. G. Conrad, K. H. Nealson, Astrobiology 1, 15 (2001). ■ This article is copyrighted as indicated in the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 130.156.1.80 On: Sat, 17 Oct 2015 18:44:29 Physics Today Super fracking Donald L. Turcotte, Eldridge M. Moores, and John B. Rundle Citation: Physics Today 67(8), 34 (2014); doi: 10.1063/PT.3.2480 View online: http://dx.doi.org/10.1063/PT.3.2480 View Table of Contents: http://scitation.aip.org/content/aip/magazine/physicstoday/67/8?ver=pdfcov Published by the AIP Publishing This article is copyrighted as indicated in the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 130.156.1.80 On: Sat, 17 Oct 2015 18:45:17 Super Donald L. Turcotte, Eldridge M. Moores, and John B. Rundle Fractures in siltstone and black shale in the Utica shale, near Fort Plain, New York. (Photograph by Michael C. Rygel.) Injecting large volumes of low-viscosity water helps energy producers extract oil and gas from shales that tightly confine those fossil fuels. But the technique also confronts technical and environmental issues. A fter rising steadily for decades, US annual production of natural gas peaked at 22.7 trillion cubic feet (Tcf) in 1973. For a decade thereafter, production generally declined as gas reservoirs became depleted. It picked up for a while after that but really took off in 2005; by 2012 natural gas production had risen to 25.3 Tcf. The rapid increase in the availability of natural gas strongly influenced gas pricing. On 1 January 2000 the wellhead price was $2.60 per thousand cf. By 1 January 2006 the price had increased to $8.00, but by New Year’s of 2012 it was down to $2.89. The impressive gas production increases and price decreases over the past decade or so are primarily due to a variety of hydraulic fracturing, or fracking, in Donald Turcotte and Eldridge Moores are Distinguished Professors Emeriti and John Rundle is a Distinguished Professor, all in the department of Earth and planetary sciences at the University of California, Davis. Rundle also holds appointments in the physics department there and at the Santa Fe Institute in Santa Fe, New Mexico. which large volumes of low-viscosity water are pumped into low-permeability (“tight”) shale formations. We call that type of hydraulic fracturing “super fracking” to distinguish it from long-established hydraulic fracturing with low volumes of high-viscosity water.1,2 An important consequence of the drop in natural gas prices over the past several years has been the substitution of natural gas for coal in electric power generation plants. As a result, carbon dioxide emissions from power plants have been reduced by about a factor of two. That said, we do not wish to minimize the environmental concerns associated with high-volume fracking. The box on page 36 spells out some of the issues. Traditional fracking has been in use for more than 50 years. Super fracking, which, like the traditional kind, is used for oil as well as gas production, is a relative newcomer; it arrived on the scene about 30 years ago and became economically viable around 1997, with profound consequences, as the natural gas numbers cited above show. Although our focus will be on the high-volume variant, we This article copyrighted as indicated the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 34 is August 2014 PhysicsinToday www.physicstoday.org 130.156.1.80 On: Sat, 17 Oct 2015 18:45:17 Figure 1. Traditional and high-volume fracking. (a) In traditional fracking treatments, a high-viscosity fluid creates a single hydraulic fracture through which oil or gas (or both) migrates to the production well. (b) In high-volume fracking, or super fracking, large volumes of a low-viscosity liquid create a wide distribution of hydraulic fractures. Fossil fuels can then migrate through the fracture network to the production well. The sketch here shows the result of a sequence of four high-volume fracking injections. Such sequential injections would not be possible without directional drilling, which creates a horizontal production well in the target stratum. a b 3–5 km 3–5 km will also have a few words to say about traditional fracking. But first we turn to an examination of the shales that house oil and gas. Fossil fuels’ underground home Just as sandstones are a rock equivalent of sand, shales are a rock equivalent of mud. They can extend horizontally for more than a thousand kilometers and have a porosity of 2–20%. The shales that are a main source for hydrocarbons are known as black shales because of their color and organic content. Their pores are typically filled with 2–18% by weight of carbon in organic compounds. A representative grain in a shale is less than 4 μm wide; surface-tension forces due to those fine grains strongly restrict fluid flow. Black shales form when large volumes of organic matter are deposited in muds beneath the sea. If the organic carbon is to be preserved, the deposition and subsequent burial must occur under anoxic conditions. That is one reason why some 90% of the world’s oil originated in well-defined periods encompassing 200 million out of the past 545 million years. The largest known region currently forming organicrich clays—future black shales—is the Black Sea. The environment in which sediments are deposited has a thermal gradient of something like 30 °C/km. At sufficient depth, time and heat produce oil from the organic material. That oil is located in a window 2–4 km below the surface where temperatures range from about 60 °C to about 120 °C. At depths of 3–6 km and associated higher temperatures of around 90–180 °C, the oil breaks down to produce gas.3 Sedimentary organic material can form oil and gas only under anoxic conditions. Thus the deposition and burial of the organics must occur in an environment with restricted water circulation— otherwise, the water would oxidize the carbon in the sediment. As noted above, the fine grains that form shale enforce that restriction via surfacetension forces. Natural fracking Oil and gas formation in black shales increases fluid pressure; the resulting hydraulic forces yield a network of fractures.4 For that natural fracking to come about, the pore pressure must be about 85% of the pressure generated by the weight of the overlying rock.5 The main factors responsible for natural fractures and their orientations include tectonic activity and the structure and mineralogy of the shale. One consequence of natural fracking is a pervasive set of fractures, such as those shown in the opening image. Although the granular permeability in shales is low, it is sufficient to permit oil and gas to flow to the closely spaced fractures, which provide pathways for vertical migration. The upward movement reduces fluid pressure and takes the fossil fuels from their source in the black shale to reservoirs that can be exploited for production, or even to the surface as oil and gas seeps. An excellent example of the results of natural fracking processes can be seen in the Monterey shale in California, the source rock for major oil fields in the Los Angeles, Ventura, Santa Maria, and San Joaquin sedimentary basins.6 The northern Santa Barbara Channel, separating the Santa Barbara coast from California’s Channel Islands, is one of the largest hydrocarbon seepage areas in the world.7 Oil and gas leak upward through natural fractures and tectonic faults in the Monterey shale. The most intense area of natural seepage is about 15 km west of Santa Barbara at the Coal Oil Point seep field, where the resulting oil slicks can be as much as 10 km long. Centuries ago the earliest Spanish settlers and English explorers recorded the existence of beach tars in the region. In some cases, natural fracking has enabled the direct extraction of fossil fuels from tight shale reservoirs. More often, natural fractures and faults allow the migration of oil and gas to high-porosity reservoirs. Once trapped there, the oil and gas can be extracted with traditional production wells. However, the fraction of the oil and gas that is recovered from the production reservoir is low, typically 20–30%. Energy producers have tried several methods to enhance recovery. One process involves flooding the production reservoir: Water or another fluid introduced at so-called injection wells drives the oil and gas to the production wells. A second process is hydraulic fracturing. As illustrated in figure 1, the technique involves the high-pressure injection of water so as to create fractures in the production This article www.physicstoday.org is copyrighted as indicated in the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded August 2014 Physics Today 35 to IP: 130.156.1.80 On: Sat, 17 Oct 2015 18:45:17 Super fracking Environmental concerns Oil and gas production utilizing high-volume fracking has several associated severe environmental problems.1 Those include the following: ‣ The need for large volumes of water. In some areas, fracking significantly reduces the water available for other purposes. ‣ Contaminated water. The water injected during fracking is subsequently returned to the wellhead adulterated by additives and natural contamination such as radiogenic isotopes from the rock. In many cases, injection wells return that water to a sedimentary layer. Such wastewater disposal creates a number of environmental concerns, including leakage and induced seismicity. ‣ Leakage of methane gas into the atmosphere. Wells in North Dakota’s Bakken shale, for example, produce gas in addition to oil. At present, the site doesn’t have enough pipeline to use all the gas extracted, so workers burn off significant quantities of it. That practice, called flaring, is clearly undesirable in terms of air pollution and greenhouse gas production and as a waste of a natural resource. Oil producers on the North Slope in Alaska must reinject gas that cannot be used. Ongoing efforts may lead to a federal requirement for reinjection in North Dakota and other localities. ‣ Leakage of methane gas or other fluids into shallow aquifers. Documented leakage into shallow layers, including aquifers, appears to be associated with the well casing itself or with the cementing of the well casing to the rock.1 Leaks of fracking fluid from shale into groundwater are unlikely because the high-volume fracking injections generally occur at depths of a few kilometers—well below groundwater aquifers, which are no deeper than 300 m. However, fracking fluids, flowback waters, and drilling muds have occasionally been spilled on the ground. ‣ Triggering of damaging earthquakes. As discussed in the main text, high-volume fracking generates numerous small earthquakes, and the possibility of a large earthquake cannot be ruled out. However, the largest earthquake attributed to high-volume fracking had a magnitude of 3.6, which is too small to do surface damage. On the other hand, some larger earthquakes, including a magnitude-5.7 quake that struck Oklahoma in 2011, have been attributed to wastewater injection.16 The documented and potential problems associated with super fracking call for regulation by state and federal agencies—and some regulations are already in place. Any regulatory framework, though, must distinguish between traditional and high-volume fracking because the environmental problems discussed in this box are not associated with traditional, low-volume fracking. reservoir and facilitate migration to the production well. Traditional low-volume fracking enhances production from high-permeability reservoirs. High-volume super fracking is the method of choice for extracting oil and gas from tight shale reservoirs. ability is between 10−9 darcy and 10−7 darcy, a good six orders of magnitude or so lower than usual for sandstone reservoirs. Super fracking, with its large volumes of water and high flow rates, was developed to extract oil and gas from them. Additives, usually polyacrylamides, decrease the viscosity of the water; the treated fluid is generally called slickwater. Typically super fracking uses 100 times as much water as traditional fracking. The objective of high-volume fracking is to create many open fractures relatively close together—so-called distributed damage.9 Those fractures allow oil and gas to migrate out of the rock and to the production well. Many of them are reactivated natural fractures that had been previously sealed. As illustrated in figure 1b, high-volume fracking involves drilling the production well vertically until it reaches the target stratum, which includes the production reservoir. Then directional drilling extends the well horizontally into that target stratum, typically for a distance of 1–2 km. Plugs, called packers in the industry, block off a section of the well, and explosives perforate the well casing. It is desirable to target reservoirs that are 3–5 km deep to ensure that the overlying material can generate enough pressure to drive out the oil and gas. The slickwater, injected at high pressure through the blocked-off, perforated well, creates distributed hydrofractures. At the end of the fracking injection, the fluid pressure drops and a fraction of the injected fluid flows back out of the well. Then production begins. Volume and viscosity Traditional fracking generally requires 75–1000 m3 of water whose viscosity has been increased by the addition of guar gum or hydroxyethyl cellulose. The objective, as shown in figure 1a, is to create a single large fracture, or perhaps a few of them, through which oil and gas can flow to the production well. A large volume of injected sand or other “proppant” helps keep the fractures open. Energy producers now routinely apply traditional fracking to granular reservoirs, such as sandstones, that have permeabilities of 0.001–0.1 darcy. (The darcy is a measure of fluid flux corrected for the viscosity of the fluid and the pressure gradient driving the flow.) Indeed, analysts Carl Montgomery and Michael Smith estimate that some 80% of the producing wells in the US have been treated with traditional fracking.8 The natural permeability of the rock allows oil and gas to migrate to the single open fracture and subsequently make their way to the production well. However, traditional fracking does not successfully increase oil and gas production from tight shale reservoirs in which few fractures exist or in which the natural fractures have over time been sealed by deposition of silica or carbonates. In tight shale formations, the granular perme- This article copyrighted as indicated the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 36 is August 2014 PhysicsinToday www.physicstoday.org 130.156.1.80 On: Sat, 17 Oct 2015 18:45:17 Small earthquakes High-volume fracking creates a distribution of microseismic events that documents the complex fracture network generated by the fracking. Nowadays something like 10% of production wells are accompanied by one or more vertical monitoring wells that have seismometers distributed along their lengths. Those seismometers can locate microseismic events in real time, and the data they provide can help optimize injection rates. Figure 2 shows a typical example, from the Barnett shale in Texas.10 The first two of four injections produced relatively narrow clusters of seismicity, whereas the third and fourth injections produced much broader clusters that indicate a less localized fracture network. A possible explanation for the difference focuses on the role of preexisting natural fractures: The narrow clusters may result from injections into the closely spaced natural fractures, whereas the broad clusters may reflect an extensive new fracturing network needed to access natural fractures. Typically, the microearthquakes accompanying super fracking would register in the −3 to −2 range on the Gutenberg–Richter scale, much too small to be felt at the surface. But the magnitude distribution of the microearthquakes satisfies the same scaling as tectonic earthquakes: The logarithm of the number of earthquakes with magnitude greater than m varies linearly with m. Thus the possibility of a larger earthquake cannot be ruled out. However, for the microseismicity associated with high-volume fracking, the b value (negative of the slope) is in the 1.5–2.5 range, whereas for tectonic earthquakes it’s 0.8–1.2. Extrapolating the linear relation suggests that the probability of a magnitude-4 earthquake arising from super fracking is something like 10−15 to 10−9, clearly very small. We now turn to some specific examples of oil and gas extraction from tight black shales. We first consider the Barnett shale in Texas. The Barnett was the site of the first high-volume fracking injections of slickwater, a technique primarily developed by Mitchell Energy beginning in the late 1980s. We next consider the Bakken shale on the US–Canada border. Unlike the Barnett, the Bakken shale produces primarily oil. We then consider the Monterey shale in California and discuss why high-volume fracking has not been successfully applied there. Barnett and Bakken The Barnett shale is a black shale that formed during the Lower Carboniferous period, 323 million–340 million years ago. Figure 3a shows the location of Fracking Fracking Fracking Fracking 600 1 2 3 4 events events events events 400 1 DISTANCE (m) In our view, high-volume fracking is successful only in the absence of significant preexisting fracture permeability. That’s because significant fracture permeability would provide pathways along which the injected fluid can flow. The result would be a fluid pressure that is too low to create distributed new fractures. We will return to that idea below, in connection with the Barnett and Monterey shales, but we acknowledge that our conclusion is certainly not universally accepted. 2 200 3 0 4 Monitoring well Injection well −200 −400 0 200 400 600 DISTANCE (m) 800 1000 Figure 2. Small earthquakes associated with four high-volume frackings of the Barnett shale in Texas. Each tiny “+” symbol on this microseismicity map shows the epicenter of a microearthquake. Collectively, the symbols reveal the distribution of fractures induced by the injected water. The monitoring well is at the origin of the coordinate system shown. The injection well is off to the right; the thin line shows its horizontal extent. (Adapted from ref. 10.) the shale, which is in the Fort Worth basin of Texas. The organic carbon concentrations in the productive Barnett shale range from less than 0.5% by weight to more than 6%, with an average of 4.5%. Production depths range from about 1.5 km to 2.5 km. The gas-producing stratum has a maximum thickness of about 300 m, is relatively flat, and has only slight tectonic deformations. Most natural hydraulic fractures in the Barnett shale have been completely sealed by carbonate deposition.11 The bonding between the carbonate and shale is weak, so a high-volume fracking injection can open the sealed fractures with relative ease.12 We suggest that once opened, the natural fractures prevent subsequent high-volume fracking injections from creating distributed fractures. Instead, the injected slickwater leaks through the natural fractures without producing further damage. Until being overtaken by the Marcellus shale in the Appalachian basin, the Barnett shale was the largest producer of tight shale gas in the US. Its annual production of 0.5 Tcf of gas is an appreciable fraction of the total national annual production of some 25 Tcf. In 2011 the US Department of Energy estimated13 the accessible gas reserves in the Barnett shale to be 43 Tcf. The Bakken shale is a black shale located in the Williston (also called the Western Canada) basin; This article www.physicstoday.org is copyrighted as indicated in the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded August 2014 Physics Today 37 to IP: 130.156.1.80 On: Sat, 17 Oct 2015 18:45:17 Super fracking a c b CALIFORNIA SASKATCHEWAN Regina Fort Worth MANITOBA CANADA UNITED STAT ES TEXAS Austin Sacramento NORTH DAKOTA MONTANA Bismarck Billings Santa Maria basin Barnett shale Bakken shale Monterey shale Ventura basin Los Angeles basin Figure 3. Show me the shale. The three maps here give the locations of important fossil-fuel-producing shales in the US. (a) The Barnett shale is in north central Texas. (b) The Bakken shale, in the Williston basin, encompasses regions of the US and Canada. (c) The Monterey shale extends along much of California. (Maps courtesy of Janice Fong.) see figure 3b. It formed during the Late Devonian– Lower Mississippian period 340 million–385 million years ago. Unlike the Barnett shale, the Bakken has yielded large amounts of oil. Most of it comes from North Dakota, which now produces more oil than any state but Texas. The Bakken shale is mostly horizontal and has little tectonic deformation. It consists of two black shale layers separated by a layer of dolomite (calcium magnesium carbonate) and is the first formation in which high-volume fracking demonstrated success at effectively extracting oil from a tight shale. The relative contributions of the black shale layers and the dolomite layer to production are not clear. But it is clear that high-volume fracking is essential for significant oil production at Bakken. The shale typically has 5% porosity, but the bulk permeability is very low, typically 4 × 10−9 darcy. Most natural fractures are tightly sealed, which allows super fracking to create distributed fractures through which oil can migrate to production wells. The producing formation typically is 1.5–2.5 km deep and as much as 40 m thick. In July 2013 about 6000 producing wells, primarily horizontal, operated in the Bakken shale. They contributed to an annual oil production rate of 300 million barrels (Mbbl), or 4.8 × 107 m3. Estimates from DOE of the oil reserves in the Bakken shale are 3.6 billion barrels (Bbbl),13 half again as much as the total US production of 2.37 Bbbl for the year 2012. Monterey The Monterey shale in California is a diverse area of organic-rich layers of black shale alternating with silica-rich beds derived principally from rocks and the shells of diatoms. The Monterey shale, much younger than the Barnett and Bakken shales, formed 8 million–17 million years ago during the Miocene epoch. Due to its relative youth, it has not had the time to become a tight black shale with sealed natural fractures. Open natural fractures are pervasive in the Monterey shale. Figure 3c indicates the location of the formation, which straddles the San Andreas Fault. It has evolved in an active tectonic environment,14 and evidence of its extensive tectonic displacements can be seen in figure 4. The deposition of the black shale occurred in several sedimentary basins, including Los Angeles, Ventura, and Santa Maria. Those basins have yielded large quantities of oil for more than 100 years. Per acre, the Los Angeles basin, which includes the Long Beach, Huntington Beach, and Wilmington oil fields, has been among the world’s most productive oil regions. The total oil extracted from California basins has been some 29 Bbbl. Annual production peaked at 394 Mbbl in 1984 and has decreased steadily to 196 Mbbl in 2012. The Monterey shale is the source of that oil, although much of the oil has been produced from younger strata into which the fuel migrated. According to DOE estimates from 2011, the total recoverable oil in the 48 contiguous states is 24 Bbbl.13 They attribute 15.4 Bbbl to the Monterey shale and 3.6 Bbbl to the Bakken shale, so the Monterey has great potential for future petroleum production. However, attempts to use super fracking to extract oil there have not been successful. In our view, the culprit is the extensive fracture permeability in the Monterey shale that has arisen from both natural fracking and tectonic deformation. The welldeveloped fracture networks in the shale have allowed some oil to migrate and be recovered, but they also prevent the buildup of the high fluid pressure required for super fracking to produce distributed fracture permeability. Questions remain In addition to the environmental issues spelled out in the box on page 36, several technical concerns will affect the long-term viability of high-volume fracking. One is the efficiency of extraction: What percent of the oil and gas in the tight shale reservoir is recovered and at what rate? Traditional oil and gas extraction consists of three stages. The primary stage extracts the oil and gas that flow to the vertical wells from the reservoir in which they are trapped. Typically, it manages to recover 20–30% of the oil and gas in the formation. The secondary stage usually This article copyrighted as indicated the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded to IP: 38 is August 2014 PhysicsinToday www.physicstoday.org 130.156.1.80 On: Sat, 17 Oct 2015 18:45:17 Figure 4. The highly fractured Monterey shale, exposed near the Hayward fault in Berkeley, California. Dark bands are black shale. Tectonic movements have brought this sedimentary rock to the surface and rotated the beds from horizontal to vertical. (Photograph by Eldridge Moores.) involves flooding the target reservoir with water, carbon dioxide, or nitrogen. Those fluids, introduced at injection wells, drive the oil and gas to production wells. Usually 40–50% of the oil and gas is recovered in stages one and two. The tertiary phase can involve steam injection to soften viscous oil, acid leaching to dissolve rock in the formation, or lowvolume fracking. All told, the three stages typically collect 60–65% of the available oil and gas. High-volume fracking of tight shale reestablishes the natural fracture permeability and also produces new fractures. But the process depends on the pressure naturally generated by the weight of the overlying rock to drive the fluid to the production well. In its reliance on natural fractures and pressure, high-volume fracking is similar to the primary stage of traditional extraction. Energy consultant George King has estimated that prior to 2006, less than 10% of trapped gas was recovered from tight shale formations1 but that subsequent technological advances have increased the fraction to as much as 45%. Unfortunately, the production rate declines with time. Typically, 65% of the total production from a super-fracking well is generated in the first year and 80% in the first two years.1 That decline in production is considerably greater than in traditional oil and gas wells and requires that many high-volume fracking wells be drilled to maintain production. Another important question is whether super fracking can be modified so that it is effective in extracting oil and gas from black shale reservoirs, such as the Monterey shale, that have open natural fractures. Would it be technically feasible, for example, to inject cement to seal the natural fractures before carrying out high-volume fracking? And can it be done in an environmentally responsible manner? The use of high-volume fracking to extract large quantities of fossil fuels is a relatively recent development. As a result, energy producers lack scientific studies on which to base technological developments and assess environmental implications. The physical processes associated with high-volume fluid injection are poorly understood. Among the issues that will require detailed study are contamination, fluid leakage, and induced seismicity. We, along with our colleague J. Quinn Norris, are among the few who have attempted to model super fracking; our study is based on a type of graph-theory analysis called invasion percolation from a point source.15 High-volume fracking is such a successful tool for economically extracting oil and gas that its use will probably continue to expand for a long while. We emphasize, however, that tight shale oil and gas are nonrenewable sources of energy. Getting the most out of the shales that confine fossil fuels will buy some time for humankind to further develop renewable sources such as wind and solar, but it will not erase the need to ultimately transition to them. We thank J. Quinn Norris for his contributions to this article and acknowledge Chris Barton, Scott Hector, and David Osleger for insightful comments and reviews of an earlier version. References 1. G. E. King, “Hydraulic fracturing 101,” paper presented at the Society of Petroleum Engineers Hydraulic Fracturing Technology Conference, 6–8 February 2012, available at http://fracfocus.org/sites/default /files/publications/hydraulic_fracturing_101.pdf. 2. J. B. Curtis, Am. Assoc. Pet. Geol. Bull. 86, 1921 (2002). 3. J. M. Hunt, Petroleum Geochemistry and Geology, 2nd ed., W. H. Freeman, New York (1996). 4. D. T. Secor, Am. J. Sci. 263, 633 (1965); J. E. Olson, S. E. Laubach, R. H. Lander, Am. Assoc. Pet. Geol. Bull. 93, 1535 (2009). 5. T. Engelder, A. Lacazette, in Rock Joints, N. Barton, O. Stephansson, eds., A. A. Balkema, Brookfield, VT (1990), p. 35. 6. R. J. Behl, Geol. Soc. Am. Spec. Pap. 338, 301 (1999). 7. J. S. Hornafius, D. Quigley, B. P. Luyendyk, J. Geophys. Res. (Oceans) 104, 20703 (1999). 8. C. T. Montgomery, M. B. Smith, J. Pet. Technol. 62(12), 26 (2010). 9. S. Busetti, K. Mish, Z. Reches, Am. Assoc. Pet. Geol. Bull. 96, 1687 (2012); S. Busetti et al., Am. Assoc. Pet. Geol. Bull. 96, 1711 (2012). 10. S. Maxwell, Leading Edge 30, 340 (2011). 11. J. F. W. Gale, R. M. Reed, J. Holder, Am. Assoc. Pet. Geol. Bull. 91, 603 (2007). 12. K. A. Bowker, Am. Assoc. Pet. Geol. Bull. 91, 523 (2007). 13. US Energy Information Administration, Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays (July 2011), available at http://www.eia.gov/analysis /studies/usshalegas. 14. T. Finkbeiner, C. A. Barton, M. D. Zoback, Am. Assoc. Pet. Geol. Bull. 81, 1975 (1997). 15. J. Q. Norris, D. L. Turcotte, J. B. Rundle, Phys. Rev. E 89, 022119 (2014). 16. W. L. Ellsworth, Science 341, 142 (2013). ■ This article www.physicstoday.org is copyrighted as indicated in the article. Reuse of AIP content is subject to the terms at: http://scitation.aip.org/termsconditions. Downloaded August 2014 Physics Today 39 to IP: 130.156.1.80 On: Sat, 17 Oct 2015 18:45:17 Biodiesel is on a roll, a subsidy-led roll. Thanks to tax-breaks for retailers and quota exemptions for farmers, world production has soared from about 300 000t in 1995 to nearly 7m t in 2006 - an annualised growth of 33%. Over the coming decade, output is expected to climb perhaps another ten-fold, which surely makes it the world's fastest-growing bulk chemical product. Ironically, biodiesel's rise comes a century later than originally planned. When inventor Rudolf Diesel showed his eponymous compression engine at the 1900 World's Fair in Paris, France, it ran on peanut oil. Although he did not name it a peanut engine, Mr Diesel did intend his motors to run on vegetable oils, which are only one process step removed from biodiesel. Despite his intentions, petroleum derivatives ended up cornering the motor fuels markets, and for one very good reason: even at today's $60-ish per barrel crude prices, they cost less. This inconvenient truth has not stopped governments around the world from pushing biofuels; indeed it spurs them on. The latest move was from the European Commission, which in January 2007 proposed to peg biofuels' 2020 share of all transport fuels at 10%. This comes on top of the 2003 EU Biofuels Directive that aims for a 5.75% share in 2010. Either target is well 22 above current levels of about 2%. Why such interest in biofuels? For one, many analysts believe that crude's price party is over: that cheap oil has permanently disappeared. This ties to another biofuels hot button: the desire for greater energy security. Better to have the local farmer growing at least some of your fuel instead of counting on supplies from notoriously unreliable exporters in, say, Russia, the Middle East or Venezuela. And then there are the farmers themselves. What better way to subsidise this numerically small yet politically mighty group than to hand them the keys to the nation's petrol tank. "*The EU has set a target for biofuels to account for 10% of all fuels by 2020 "*Biodiesel made from rape oil creates N20 emissions over its entire lifetime "*Growing rapeseed releases large amounts of potent greenhouse gas N20 Powerful argument? These seem to be solid reasons in themselves, yet the most powerful argument for boosting biofuels, the EU says, is to combat global warming. As the 10% by 2020 target was announced, European Commission president Jose Barroso crowed: 'We can say to the rest of the world - Europe is taking the lead. You should join us in fighting climate change.' But do biofuels really reduce global warming? To answer this crucial question, SRI Consulting (SRIC) recently sized up biodiesel made from rape oil - Europe's and the world's predominant feedstock - versus petroleum die- References 1 Well-to-Wheels analysis of future automotive fuels and powertrains in the European context WELL-TO-TANK report version 2b, May 2006. European Council for Automotive R&D, CONCAWE and European Commission Joint Research Centre. Available at http://ies. irc.ec.europa.eu/WTW 2 L Brown es al, Atmos. Environ. 2002, 36 (6), 917. sel refined from crude oil - and came to answers that, although politically incorrect, are worth considering. We inventoried the lifetime greenhouse-gas emissions of RME (rape methyl ester biodiesel) and petroleum diesel, as commonly produced in Europe, from production on through to combustion in an automobile. For RME, that lifetime starts with growing rapeseed on a farm, which is then crushed to extract oil, which is chemically processed into biodiesel, which is burnt in an engine. For petroleum diesel, the lifetime begins as crude oil in a well, which is produced, refined and then also burnt. We used emissions data for these steps from a variety of public sources, including SRIC's own process models of biodiesel synthesis. The resulting inventories show that some two-thirds of RME's greenhouse gas emissions occur during the farming of rapeseed, where cropland emits N20 that is 200 to 300 times as potent Chemistry &Industry - 23 April 2007 Petroleum diesel vs biodiesel in its global warming potential as C02 itself. N2 0 emissions have been researched heavily in recent years, and they appear to be a function of four main factors (see box). Fertiliser production and tilling also generate significant carbon emissions, while everything else in the life cycle, including electricity generation, accounts for only about 15% of the CO2 equivalent (CO2e) total. Petroleum diesel, by contrast, emits some 85% of its greenhouse gas emissions in the final use stage, from being burnt in the engine. Based on the results of our analysis, it turns out that RME and petroleum diesel are almost equal on global warming contribution per unit of energy delivered. If rapeseed is grown on dedicated farmland, which over time is likely to be the case, then the contest is a draw: RME accounts for nearly the same amount of C0 2e per kilometre driven. However, if rapeseed is grown on land that otherwise would be set aside temporarily, which means they will emit significant quantities of N 20 whether fallow or planted, RME wins - emitting about 25% less CO2e per kilometre driven. Useful comparison An even more useful comparison, however, involves comparing greenhouse gas emissions normalised by land use, either to grow rapeseed or trees. If petroleumn diesel were substituted for biodiesel, land would be freed up to grow Im p a ct s I of b oi [ai e some other crop, including a forest that would function as a carbon dioxide sink. What would this do to the greenhouse gas balance? To answer that question, we used figures from the well-known EcoInvent database for the production of air-dried, sawn hardwood. Plugging these data into our inventory model gives a hands-down win by a factor of almost 2:1 for petroleum diesel. For minimum greenhouse gas emissions, set-aside arable land should therefore be used as forest and not for growing biodiesel. To answer the question posed at the start of this article: no, the trade-off of substituting biofuels for fossil fuels - at least in the case of RME versus petroleum diesel - does not give a payoff with respect to global warming. Because emissions of N20 (laughing gas) are a hot topic of research and crucially important to the study's conclusions, we looked very carefully at four sensitivities: " "*Quantity of nitrogenous fertiliser used: Our figure, again from the LCA Food Database, squares with those estimated by the United Nations' Intergovernmental Panel on Climate Change (IPCC) for rotated crops. "*N20 emissions: These emissions are critical and also subject to ongoing debate by, among others, the European Council for Automotive R&D, the European CommissionI and the IPCC. We have used a figure recently estimated by a group of UK researchers 2 that accounts for soil effects as well as whether fields are cultivated or fallow. Broader picture But before policymakers rush to ditch biofuels altogether, they might want to consider a rather broader picture. In addition to our study of global warming, we also compared the two fuels in terms of a range of other environmental impacts - from eco and biological toxicity to ozone layer depletion and acidification. To do so, we weighted the complete emissions inventories of each system, not just greenhouse gases, by using a commonly used impact assessment method. The answer is equivocal: petroleum diesel comes out ahead in five categories; biodiesel comes out ahead in the other five. l i Ieu Yield of rapeseed: We used a figure - sourced from the LCA Food Database, published by Denmark's Ministry of Food, Agriculture and Fisheries - that is slightly below the average for Germany, which has the EU's highest yields. Thanks to improved farming methods, these have nearly doubled from their levels of the 1970s. At the same time, these improvements require more fertiliser. "*Organic farming: Emissions of N2 0 are substantially lower from organic farms that use less fertiliser, but so are rapeseed yields. Eric Johnson, editor of Environmental Impact Assessment Review, is based in Zurich, Switzerland Russell Heinen, vice president of SRI Consulting and manager of its Process Economics Program, is based in Houston, Texas, US [ero i Biodiesel and petroleum diesel were compared inten different environmental impact categories. The figure shows relative impacts, with one fuel set at 100% and the other at its relative level to that. Biodiesel comes out lower (better) in five categories, petroleum diesel inthe other five. 0 120 Biodiesel Petroleum Diesel 100 80 60 40 20 0 -20 terrestrial ecotoxicity marine aquatic ecotoxicity Chemistry &Industry - 23 April 2007 abiotic depletion human toxicity fresh water aquatic ecotoxicity eutrophication acidification photochemical oxidation ozonelayer depletion global warming (GWP100) 23 COPYRIGHT INFORMATION TITLE: The race is on SOURCE: Chemistry & Industry no8 Ap 23 2007 PAGE(S): 22-3 The magazine publisher is the copyright holder of this article and it is reproduced with permission. Further reproduction of this article in violation of the copyright is prohibited. To contact the publisher: http://sci.mond.org/
Purchase answer to see full attachment