Hydraulic Fracturing 9780841231214, 0841231214, 9780841231221

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Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.fw001

Hydraulic Fracturing: Environmental Issues

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.fw001

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

ACS SYMPOSIUM SERIES 1216

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.fw001

Hydraulic Fracturing: Environmental Issues Donna L. Drogos, Editor University of Wyoming Laramie, Wyoming

Sponsored by the ACS Division of Environmental Chemistry, Inc.

American Chemical Society, Washington, DC Distributed in print by Oxford University Press

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.fw001

Library of Congress Cataloging-in-Publication Data Names: Drogos, Donna L., 1943- editor. | American Chemical Society. Division of Environmental Chemistry. Title: Hydraulic fracturing : environmental issues / Donna L. Drogos, editor, University of Wyoming, Laramie, Wyoming ; sponsored by the ACS Division of Environmental Chemistry. Description: Washington, DC : American Chemical Society, [2015] | [Oxford] : Distributed in print by Oxford University Press | Series: ACS symposium series ; 1216 | Includes bibliographical references and index. Identifiers: LCCN 2015046407 (print) | LCCN 2015047109 (ebook) | ISBN 9780841231221 (alk. paper) | ISBN 9780841231214 () Subjects: LCSH: Hydraulic fracturing--Environmental aspects. Classification: LCC TD195.G3 H9375 2015 (print) | LCC TD195.G3 (ebook) | DDC 363.738--dc23 LC record available at http://lccn.loc.gov/2015046407

The paper used in this publication meets the minimum requirements of American National Standard for Information Sciences—Permanence of Paper for Printed Library Materials, ANSI Z39.48n1984. Copyright © 2015 American Chemical Society Distributed in print by Oxford University Press All Rights Reserved. Reprographic copying beyond that permitted by Sections 107 or 108 of the U.S. Copyright Act is allowed for internal use only, provided that a per-chapter fee of $40.25 plus $0.75 per page is paid to the Copyright Clearance Center, Inc., 222 Rosewood Drive, Danvers, MA 01923, USA. Republication or reproduction for sale of pages in this book is permitted only under license from ACS. Direct these and other permission requests to ACS Copyright Office, Publications Division, 1155 16th Street, N.W., Washington, DC 20036. The citation of trade names and/or names of manufacturers in this publication is not to be construed as an endorsement or as approval by ACS of the commercial products or services referenced herein; nor should the mere reference herein to any drawing, specification, chemical process, or other data be regarded as a license or as a conveyance of any right or permission to the holder, reader, or any other person or corporation, to manufacture, reproduce, use, or sell any patented invention or copyrighted work that may in any way be related thereto. Registered names, trademarks, etc., used in this publication, even without specific indication thereof, are not to be considered unprotected by law. PRINTED IN THE UNITED STATES OF AMERICA In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.fw001

Foreword The ACS Symposium Series was first published in 1974 to provide a mechanism for publishing symposia quickly in book form. The purpose of the series is to publish timely, comprehensive books developed from the ACS sponsored symposia based on current scientific research. Occasionally, books are developed from symposia sponsored by other organizations when the topic is of keen interest to the chemistry audience. Before agreeing to publish a book, the proposed table of contents is reviewed for appropriate and comprehensive coverage and for interest to the audience. Some papers may be excluded to better focus the book; others may be added to provide comprehensiveness. When appropriate, overview or introductory chapters are added. Drafts of chapters are peer-reviewed prior to final acceptance or rejection, and manuscripts are prepared in camera-ready format. As a rule, only original research papers and original review papers are included in the volumes. Verbatim reproductions of previous published papers are not accepted.

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In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Editor’s Biography

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Donna L. Drogos Donna L. Drogos, P.E., holds a Bachelor’s of Science degree in Civil Engineering from the University of California at Berkeley, 1988; a Master’s of Science degree in Environmental Engineering from the Georgia Institute of Technology, 2014; and is a Registered Civil Engineer in the state of California. Currently, she is pursuing a Doctorate in Civil Engineering at the University of Wyoming. Her professional practice has focused on soil and groundwater contamination, groundwater remediation, and contaminant hydrogeology, and she has experience as a regulator, responsible party, and consultant for subsurface contamination sites. Ms. Drogos also managed an engineering division at a regulatory agency and is a member of the American Chemical Society and the National Groundwater Association.

© 2015 American Chemical Society In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.pr001

Preface High volume hydraulic fracturing of deep shale deposits has transformed the oil and gas industry, catapulting the United States (U.S.) into the biggest oil and natural gas producer in the world, surpassing Russia as of June 2015. Hydraulic fracturing has been a game changer providing an important measure of energy independence for the U.S. As one expert put it, “Shale deposits are a gift from God.” Hydraulic fracturing operations in North Dakota’s Bakken Shale, in the Marcellus formation in Pennsylvania, West Virginia, and Ohio, in Texas’ Eagle Ford and Barnett Shale, and in the vicinity of Pavillion, Wyoming, Bainbridge, Ohio, and Dimock and Dunkard Creek, Pennsylvania are the subject of increased media, public, and regulatory attention. New potential shale plays across the U.S. are also being examined, including the Monterey shale formation in California where hydraulic fracturing is a timely and significant environmental issue with California’s recently enacted hydraulic fracturing regulations and published scientific studies. Heightened interest in hydraulic fracturing is also found worldwide, particularly in the United Kingdom, France, and Poland where development of natural gas from unconventional sources are seen as a path to energy independence. More than half of the world's shale oil resources are located in Russia, China, Argentina, and Libya, and development of these resources is just beginning. Concurrent with the increased development of unconventional hydrocarbon resources are concerns over perceived risks to the environment that have been raised at hydraulic fracturing locations throughout the U.S. The injection of millions of gallons of drilling fluids with chemical additives in boreholes extending for miles to crack the shale and release oil and methane has led to reports of contaminated water supplies, releases of chemically contaminated flowback fluids, air pollution, increased greenhouse gas emissions, and induced earthquakes. Proposals for acid fracturing have also raised concerns for the environment. The 2015 U.S. Environmental Protection Agency (USEPA) report determined that hydraulic fracturing has not led to widespread impacts to drinking water resources. However, the USEPA noted specific instances could lead to contamination, such as wells with inadequate casing and cementing, improperly handled or treated flowback and production fluids, and stimulation in formations containing both oil and gas and drinking water resources. High volume fracturing of deep shale deposits also produces large quantities of wastewater over the production life of the well. The wastewaters are a mixture of the salts, metals, radionuclides, organics, and microorganisms in deep groundwater and dissolved from the geologic formation, as well as the introduced hydraulic fracturing fluids. The exact composition varies considerably ix In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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and depends upon the specific shale composition, the fracturing fluid chemical formulation tailored to that formation, and the source water for the hydraulic fracturing fluid. It is also dependent upon whether the wastewater is the initial flowback water produced in the first weeks of well development or the long-term production waters generated over the lifetime of the well. The composition of the injected fracturing fluid also alters the chemical composition of the formation water and the resulting production water. These biogeochemical changes occurring in the millions of gallons of hydraulic fracturing wastewater creates a unique dilemma for the disposal and potential reuse of these waters. Traditional disposal options, such as municipal wastewater treatment plants and deep injection wells, are now less available due to public concern over subsequent discharge to streams used as drinking water sources and the increasing reports of induced seismicity. Existing treatment options such as desalinization become cost prohibitive in treating wastewaters that are many times saltier than seawater. Water reuse is becoming common often requiring new treatment technologies to make the water suitable for reuse in the hydraulic fracturing process. These technical challenges posed by hydraulic fracturing have fostered increased research into the technologies needed to develop these oil and gas resources in an environmentally sound manner. The American Chemical Society (ACS) symposiums were the catalyst for the chapters in this volume focusing on the latest information on the environmental aspects of hydraulic fracturing, including technical challenges, environmental effects, and the political and regulatory climate. These works provide an opportunity to explore the results of ongoing research and consider multidisciplinary approaches needed to meet the challenges posed by this technology. I thank the many authors who contributed their works to this volume, ACS, and the ACS Environmental Chemistry Division for their support of the hydraulic fracturing symposiums. I especially thank Rafael Delgadillo for his unwavering support and encouragement on this project and on all of my other professional and educational pursuits.

Donna L. Drogos Department of Civil & Architectural Engineering University of Wyoming 1000 E. University Ave. Laramie, Wyoming 82071, United States [email protected] (e-mail)

x In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Chapter 1

Environmental Aspects of Hydraulic Fracturing: What Are the Facts? Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch001

George E. King* and Danny Durham Apache Corporation, 2000 Post Oak Blvd., Suite 100, Houston, Texas 77056-4400, United States *E-mail: [email protected]

Hydraulic fracturing is an established oil and gas well stimulation technique that has been in play in various forms for over sixty years and is critical to today’s United States (U.S.) production of most oil and gas resources (Montgomery, C., Smith, M. Hydraulic Fracturing: History Of An Enduring Technology. SPE JPT 2010, 62, 12, 26-32). As with any industrial activity, there are risks, both immediate and latent that must be considered. Concerns have been raised recently of ground water contamination, air pollution and other problems that may occur either as routine production activities or as a result of fracturing. These issues are complicated since oil and gas, with a myriad of co-generated hydrocarbon molecules from alkanes to ring compounds of benzene, toluene and xylenes, are simultaneously produced by naturally occurring thermal and pressure driven maturation reaction of some forms of organic carbons laid down with the sediments. Sources of many of these hydrocarbons include the organicrich shales that were deposited throughout many geologic time periods and in most parts of the world (Toutelot, H. Black Shale – its Deposition and Diagenesis. Clays and Clay Minerals, 1979, 27, 5, 313-321). As oil and gas is produced, some moves out of the shales and may be trapped in rock containments called reservoirs, but when these reservoirs are filled or when they are absent, the hydrocarbons rise via buoyancy towards the surface forming weathered or bacterial altered deposits near surface, or co-occupying space with subterranean water reservoirs, both brine and fresh. © 2015 American Chemical Society In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Many concerns of potential pollution from hydraulic fracturing are actually concerns of materials transport, well construction, hydrocarbon production or distribution. This chapter will examine the direct impact of hydraulic fracturing as a primary target and the associated activities of hydrocarbon development as a secondary effort, using both historical performance and scientifically sound research methods.

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Hydraulic Fracturing: What Is It? Oil and gas well fracturing, in the most simple of terms, creates a crack or fracture through hydrocarbon bearing rock using pressure and an injected water, oil or gas-based fluid to oppose insitu stresses and rock strata tensile strength to create a fracture that may grow vertically and laterally outward from the well (1). After the fracture is initiated at the wellbore and widened by increasing injection rate, a proppant material, usually round sand or man-made ceramic, is carried into the fracture by the injected fluid, packing the fracture with sufficient proppant to maintain a stable flow path along the fracture after the hydraulic fracturing pressure is released. Selection of types and volumes of both fluid and proppant depend on the geologic characteristics of the rock and the requirements of fracture flow capacity to enable hydrocarbon fluids to flow from the formation toward the wellbore. Sub-surface elements of oil and gas well developments and hydraulic fracturing are relatively unique among engineering endeavors in that the final product; in this case the well and the hydraulically-formed fractures, cannot be visibly examined beyond the limited extent of the well’s interior piping, and therefore must be monitored remotely by various fit-for-purpose technologies. Added to complexity is the widely varying depositional geology of the earth where oil and gas is evolved and often trapped. Fracture shape varies with the specific conditions but is usually in the range of a few hundred feet along vertical and horizontal planes within the rock with lateral orientation dictated by stresses within the rocks. At depths greater than about a thousand feet, the weight of the overlying rock forms a large vertical stress, σv, which is usually greater that either the maximum horizontal stress, σhmax, or the minimum horizontal stress, σhmin; meaning fractures created in this stress environment will be vertical as the lower horizontal stresses are easier to push apart. Native stress fields within the rock, namely σhmax and σhmin, force the fracture to grow perpendicular to the minimum horizontal stress (the σhmin is easier to push back than the σhmax). Fractures leaving a vertical well will usually develop along the wellbore, growing upward until the limiting factors of leak-off, barriers and rock stresses stop the growth. Fractures leaving a horizontal well may travel along the wellbore or at an angle to the wellbore depending on the direction in which the horizontal well is drilled, Figure 1. The intersection of a transverse fracture with the horizontal wellbore may be a tortuosity restriction in conventional formations (non-shales), but is usually an acceptable flow intersection in unconventional completions. 2 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 1. Orientation of wellbore to fracture direction. This is a critical element of wellbore orientation design. Factors such as natural fractures, bedding planes (sediment deposition streaks that accentuate or limit flow), and brittle or ductile rock all combine to shape the fracture. The intersection of the fracture with the wellbore is controllable only as much as the wellbore can be guided by directional drilling in the subsurface. In formations where fracturing is required, the wellbore acts as a “platform” from which to place fractures into the oil or gas filled rocks. The intersection of the fracture along the vertical well is the easiest to describe since the fracture follows the vertical wellbore until it limited by formation and application restraints. The natural containment barriers in reservoirs are extremely strong; proven by the fact that much of the low density oil, gas, and connate water remained trapped there even after millions of years of major earthquakes and other tectonic events. Fracture growth is limited by both natural and applied forces and factors. Changing depositional environments have shaped the rock strata for millennia, creating rock layers with different characteristics, many of which cannot easily be fractured. These fracture barriers and in situ stresses control the extent to which a fracture can develop, but are generally beyond the control of surface operations. The major fracturing design mechanism that is at least partly within the control of the fracturing applier is the type, volume, and injection rate of fracturing fluid. Targeted formations for the oil industry are those with sufficient open space between the rock grains (porosity) and possessing sufficient open passages between the pores to allow fluids to flow through the rock (permeability). As a fracture grows outward from the well, some of the injected fluid is continually lost to the permeable formation, reducing the pressure in the fracture and eventually stopping fracture growth as the total leak-off rate equals the injected rate. As fluid is lost from the volume in the fracture, the proppant is continuously concentrated and soon reaches the point where a screen-out (proppant “bridges-off”) occurs in the fracture and halts fracture fluid injection. Attempting to continue injecting beyond this leak-off dictated limit is futile, adding expense without possibility of economic benefit. The upper limit of pressure and fracture fluid injection rate is set by the size and strength of the pipe and the length of the wellbore to the 3 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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point of fracturing. Increasing friction pressure losses at higher flow rates place an upper limit on injection rate. Geology may be the biggest natural control of all and is always a major factor in the ability to generate oil, to produce large structures or “traps” that can produce conventional reservoirs and also controls the ability to reach the hydrocarbon deposits with the technology in place at the time. The only constant in the geology of the Earth is change, as attested to by millions of years of earthquakes, volcanic activity, mountain erosion, natural seeps of oil, gas and salt water, and a thousand other continuously changing processes, large and small. The need for hydraulic fracturing depends on the natural flow capacity or permeability of the formation. Economic flow from the earliest wells depended on the wellbore contacting formations with high natural flow capacity. As hydrocarbon reserves in these high permeability formations ran low, attention turned to technologies that could accelerate hydrocarbon flow from lower permeability formations. Fracturing was one of the main technologies that consistently improved flow. Marine shales that are the target of much of the oil and gas exploration today are the source for most non-bacterial deposits of oil and gas (2). Gas and oil-creating shales differ from sandstones by having extremely fine matrix particles, usually 5 to 20 microns in diameter and high total porosity that is poorly connected by restricted pore throats barely larger than an oil molecule. The permeability of these shale rocks are on the order of 10 to 1000 nanodarcies, although some shales have been naturally fractured by geological uplifts or other tectonic events and may have permeabilities through the natural fractures that are two or three folds higher than the permeability of the shale matrix. Total organic carbon (TOC) in prospective hydrocarbon-developing shales is usually 1% to 10% by volume, mixed within the rock-forming debris and deposited with the silt-sized particles and radiolaria (protozoa) skeletons. After burial with heat and pressure from the earth over geologic time, some of the organics may mature into a varied composition of hydrocarbons in a “thermogenic” action involving pressure and high temperature. Roughly 96% of seep gas and all of the seeping oil comes from thermogenic sources (3). As hydrocarbon reserves have declined, these low permeability shale formations, part of the vast shale belts of the world, have become the oil and gas reserves for the future. Hydraulic fracturing in these ultra-tight formations is a flow enabling technology and production would not be possible without it. Conventional formations (those which do not require fracturing to accelerate or enable flow of fluid in its pores) hold only a fraction of the total oil and gas generated in source rocks over millions of years. Hydrocarbons migrate out of the source rocks over geologic time and are carried upward by buoyancy with some oil and gas being trapped by the natural geologic traps that form the thousands of oil and gas fields around the world, with the remainder of escaping hydrocarbons traveling upward to the surface, often fully or partly oxidized to CO2 or being degraded by bacteria into a thicker hydrocarbon mass that is near-surface or seeps out at the surface. This upward hydrocarbon migration forms thousands of natural oil and gas seeps across the globe that over-lie depositional basins that are or have been active drilling and oil production areas. The oil and gas “springs” of New 4 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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York and western Pennsylvania (described in 1636 and mapped in 1748), the La Brea tar pits, the Coal Point seeps in the Santa Barbara Channel, Lake Guanoco in Venezuela, and the Pitch Lake in Trinidad, are western hemisphere examples of these historic oil seeps (4). The vast reserves of western Canadian Tar Sands are also examples of this hydrocarbon migration and near-surface degradation. As hydrocarbon migrates upward, the hydrocarbons that are not trapped in impermeable rock structures move further upward and are often trapped in rock layers which may also hold fresh or salt water. Documented cases of oil and gas sharing the same reservoirs are common. The history of oil and gas well development reaches back nearly 200 years in the U.S. to William Hart’s first shale gas well drilled near Fredonia New York in 1821, which stuck flowing gas at a depth of 28 feet. Edwin Drake’s purpose-drilled oil well, about sixty miles southwest near Titusville Pennsylvania, struck flowing oil at 69-1/2 feet. These two very early wells demonstrate that it should not be a surprise that oil and gas often cohabitate shallow fresh water aquifers in the areas of natural seeps (5). As the petroleum industry was developed in areas like Pennsylvania and the Santa Barbara channel, a notable decrease in emissions from some seeps has been documented. Wells drilled into the seep-powering source rocks of the coal point seep have reduced initial emissions over 50% (6). There is a level of risk of pollution in every human or natural endeavor. Pollution by oil and gas from seeps is a natural occurring act demonstrated by the volume of gas and oil that flows from tens of thousands of natural seeps, both onshore and offshore. Estimates of world-wide methane emissions from natural seeps range from about 45 terragrams (Tg) or about 6.4 billion cubic feet (bcf) per day (2, 7). Since the 1800’s, the oil and gas industry has gone from a frantic and frequently unruly place to a highly scientific, engineered, and technical world. It is useful to look back a few years and see the advancements in the oilfield and how technology development has changed the energy industry, even in the last few years. Pollution from wells and the associated processing and distribution systems has been demonstrated to be preventable if the companies and governments that are involved in production will operate in a responsible manner. The fracturing process, using fresh or salt water, chemicals and proppant, has been used over a million times with very few problems (1). Potential for pollution by fracturing exists but has been rated as a low risk by numerous studies, particularly if safer chemicals are used and the wells are designed to operate successfully during and after the fracturing treatment (8). Most problems in actual field studies have been identified as transport (major) and well construction (minor) (8–10). Although it would be easy to identify the risks only from hydraulic fracturing, the fracturing technique would not be applied without the other well development components, e.g., drilling, well construction, materials transport activities, produced water handling and production. The number of activities involved in drilling a well and the time and money spent on each varies widely. Figure 2 estimates most of these activities for US onshore, with estimates of time and money involved in each. Time and cost in other areas of the world will vary widely depending on but not limited to location, 5 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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government requirements, skill availability, available data on the geology and local infrastructure. Fluid flow through rocks must be through the pores and/or open natural fractures. Permeability is generally proportional to the square of the size of open passages through the rock although an exact linkage between pore dimensions and permeability is only possible in rocks with relatively consistent pore size and pore connections (pore throats) with single phase fluids with no wetting. Calculating or assuming a single permeability for a formation using the Darcy equation (an empirical equation developed in the 1850’s) is problematic since formation matrix permeability, particularly in shales, may vary by two or more orders of magnitude and the extremely high capillary blocking pressure in nanometer to micro meter-sized pores and fractures may make Darcy law unusable for precise prediction. Additionally, significant flow through ultra-low permeability shales is thought to travel in the natural fractures where width of the fracture is highly variable or through macro pores which make up only a small percent of the total effectively-connected porosity (11). Middle Eastern and Gulf of Mexico deep water oil and gas reservoirs are among some of the highest permeability hydrocarbon reservoirs while gas and oil shales are very low permeability, often with permeability ranges of five nanodarcies to over a thousand nanodarcies (1 microdarcy). Shale reservoirs, whether they contain gas or liquids are in a similar range of permeabilities; however, gas, which has a much lower viscosity than oil, can be more easily targeted by fracturing stimulation in low permeability formations than can the higher viscosity oil. A minimum permeability of formations that can be economically stimulated depends on average effective permeability, produced fluid viscosity and economics of the development. A generalized comparison of the typical permeability ranges of different rocks is illustrated in Figure 3. Each formation has a range of permeability and the deposition environment and post depositional modification is often the major control. Fracturing is used in the lowest permeability reservoirs, such as shale, to enable flow, while a different fracturing job design is sometimes used in higher permeability formations to accelerate flow. The job type and the design depend on type of fluid being produced and specific rock characteristics. Some shales have permeabilities that are so low that the velocity of liquid flow through their pores cannot be directly measured by flow in laboratory tests. In these cases, although the total amount of hydrocarbon in place may be exceptionally large, the ability to recover the potential resource is restricted by time. The lower the formation permeability, the more fracture-to-formation contact area is needed to provide access to the micro-cracks and small natural fractures that offer higher flow capacity than the matrix. Creating extremely large contact areas requires large volumes of fracture fluids. Fractures are usually very narrow and may close completely if sufficient proppant is not placed to offset the closure pressure of the rock. Examples of fractures in rock at a depth of about 4500 feet are shown in Figure 4. These fractures, filmed with a downhole television camera in a well with an open-hole pay zone have a characteristic width of about 1/8th to ¼ of an inch (3 to 6 mm) 6 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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and their flow capacity is several orders of magnitude higher than flow through the matrix of the rock.

Figure 2. Activities and estimates of time and cost for an onshore U.S. multiple well development.

Figure 3. Permeability range comparison of rocks on a log scale. The low end of the permeability scale is matrix permeability while the upper end of permeability is through closed or open natural fractures. 7 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 4. Downhole camera pictures of fractures in vertical wells at depths of about 4500 ft (~1400 m) (12). These pictures are still shots of video recordings in open hole wells in west Texas in 1970’s. Top Left – Fractures interrupted by a thin shale layer. Top Right – Fracture propped open by a rock fragment. Bottom Left – fracture at a pressure of simple fresh water hydrostatic. Bottom Right – same fracture as on left, except opened wider by injection pressure. Most oil and gas zones that are targets for fracturing are three thousand to over ten thousand feet deep and most fresh water sands are less than 300 to 1000 feet deep so separation is usually adequate. Separation between top of fracture and the fresh water table is often ½ to over one mile, thus potential for a fracture to even be close to a fresh water sand is very remote in most cases. Where fresh water and oil or gas zones are close together in very shallow or mixed deposits, extra care with well construction is necessary and fracturing is not commonly used. Fracturing effectively increases the size of the area that can be economically drained, thus fewer wells are required to produce the oil and gas from a field. In a moderate permeability reservoir a fractured vertical well can produce oil or gas from an area that may take 3 to 5 or more unfractured wells depending on formation permeability. Reducing footprint area drives conservation of land surface area and reduces waste. Fracturing can accelerate production from low to moderate permeability reservoirs and enable gas and oil production from those reservoirs with permeability so low they will not flow on their own. To optimize production from the lowest producible formations, which include the various gas and hydrocarbon liquid producing shales, two established technologies – fracturing and deviated wells were joined, starting in the early 1970s – with spectacular results (13). Using horizontal wells with lengths of one to two miles (1.6 to 3.2 km), and creating fractures about every 30 to 75 feet (9 to 23 m), reduced well count 8 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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again. A multi-fractured horizontal well in a very low permeability reservoir (0.0001 millidarcy [md]) may replace ten to twenty fractured vertical wells. This reduction in total well count is highly significant since the only documented subsurface leak paths from wells are small amounts of seepage along the vertical section of the wellbore (14). Reducing the well count by an order of magnitude and placing a long unperforated, cemented vertical well section, often behind an additional steel casing and cement barrier, sharply reduces methane or oil leak risk, regardless of the well design or location. Horizontal wells, which can have a horizontal displacement or “reach” of several miles, also enable wells to be located on remote pads or drilling plots away from urban or sensitive areas. One example of this from the Horn River area of British Colombia is shown in Figure 5 (15). This six acre pad, with twelve wells, each with 12 to 18 fracture stages of 1 to 4 clusters per stage, effectively and economically produces gas (at a depth of eight thousand feet) from beneath six thousand acres of forest. This type of development achieved a 93% reduction in surface area footprint over the surface area that would have been required to develop the same reservoir area requiring over ten times more fractured vertical wells.

Figure 5. An Apache Corporation six-acre pad with twelve horizontal, multi-fractured wells that access 6,000 gross acres of shale gas reservoir. Photo courtesy of Brad Affleck (16).

One of the most frequently voiced concerns about hydraulic fracturing is that fracturing would contaminate groundwater with methane gas or oil. Potential to fracture into water sands from deep hydrocarbon zones is exceptionally low as shown by microseismic monitoring data that established the distance between the “top” of fractures and the bottom of the deepest water zones in thousands of fracture treatments in the Barnett Shale, Table 1 (17). This microseismic database contains nearly four thousand hydraulic fracture treatments with clearances from the tops of fractures to the base of the deepest fresh water in each fracture treatment in four major shale fields. 9 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Shale

Number of Fracs with Microseismic Data

Primary Pay Zone Depth

Fresh Water Depth [Typical] (Deepest)

Typical Distance between top of Fracture and Deepest Water

Closest Approach of Top of Fracture in Shallowest Pay to Deepest Fresh Water

Barnett (TX)

3000+

4700′ to 8000′

[500′] (1200′)

4800′

2800′

Eagle Ford (TX)

300+

8000′ to 13,000′

[200′] (400′)

7000′

6000′

Marcellus (PA)

300+

5000′ to 8500′

[600′] (1000′)

3800′

3800′

Woodford (OK)

200+

4400′ to 10,000′

[200′] (600′)

7500′

4000′

10

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Table 1. Fracture Height-Growth Limits in Four Major U.S. Shale Plays

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Smaller data sets for Eagle Ford, Woodford, and Marcellus show the same type of response. Fractures are typically very limited in vertical height development (17).

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Drilling and Well Construction Although the action of fracturing rock is rarely a threat to groundwater supplies, well construction has been demonstrated to be a potential pollution problem in some studies. The most significant potential leak pathway for methane is either through the completion barriers (casing and cement pairs) from inside to outside or along the vertical cement isolation sheath that forms the final seal after casing has been run. Well construction, indicated by several studies to be a minor but persistent leak potential, requires a closer look for pollution potential. The Norsok D-010 report on well integrity in drilling and well operations defines the minimum performance-oriented requirements and guidelines for well design, planning and execution of safe well operations and defines well integrity as “Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well” (18). Documented research projects covering well failure and leak information on several hundred thousand wells worldwide with leak type, rate and frequency indicate that although some wells do have small seepage leaks, the fraction leaking are a small subset of the total and a very small number of the leaking wells are by far the worst offenders (9, 10, 14, 19). The objectives of well construction include the following: •

• •

Isolation of any produced fluids within the well from the formations and fluids above the pay zone. This protects groundwater and the producible mineral resource from contamination. Protection of the casing exterior from chemical attack and load impingement. Setting of multiple nested barriers and designing a well for containment in the event of an inner barrier failure (9). Cement and steel are the main cornerstones of establishing effective isolation over the life of the well. Steel alloy pipe has evolved over the past century and offers strength and corrosion resistance that was unavailable fifty years ago. The weak point in casing and tubing design is usually the threaded connection. Connection selection and connection make-up procedures may be problem causes in some operations; however, highly effective connections and proven make-up procedures are available.

As the well is drilled, the drilling is interrupted at intervals dictated by formation pressure, fluid type and rock strength characteristics, and steel pipe is run to the bottom of the drilled interval and then cemented in place. Cement slurry (powdered cement, mixed with water – no sand or gravel) is pumped down the casing and up the annulus between the casing and the drilled hole. Once set, cement has similar compressive and tensile strengths to the rocks through which 11 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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the hole has been drilled (in the range of five thousand to over ten thousand psi unconfined rock compressive strengths). The cementing step is actually a series of actions including clearing the hole of cuttings and highly gelled drilling fluids, then cleaning the pipe and casing walls to remove filter cake and other coatings before circulating cement into place. Figure 6 conveys the actions in a simple step-wise schematic of a generic cement job.

Figure 6. A sequence of basic operations involved in well completions starting with the cementing activities involved in surface casing installation to isolate and protect fresh water. Effectively cementing the annulus between the outer casing body and the drilled hole requires pipe be sufficiently centralized and proper cementing procedures be followed. Amount of cement required for a good seal varies with conditions but even zones of five thousand psi or more can be isolated with as little as 50 feet of properly blended and placed cement (20). Typical cementing zone lengths range from two hundred feet (60 m) to over a thousand feet in a single cementing stage. Full columns of cement (total depth to surface) can rarely be run in a single stage without reverting to light weight cement or two-stage jobs because of formation fracturing potential with the dense (16 pounds per gallon cement. The majority of wells do not pollute, but some obviously have done so (21, 22). Well construction improvement leading to better isolation is a major goal within the industry. Hydrocarbon producing wells are a nested collection of pipe, cement, seals, and valves that form multiple barriers between produced well fluids and the outside environment. The concept of well design is if the inside barrier fails (e.g., a leak in tubing allows sustained pressure in the annulus), the next barrier will prevent 12 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

leakage outside of the well – essentially a barriers-within-barriers. Modern well design favors more barriers at the surface and across protected water zones and fewer barriers toward the bottom of the well where the perforations and fractures are placed to encourage flow into the well.

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Cementing and Isolation Testing Monitoring and evaluating cement quality, bonding, strength and durability is a science itself with over a thousand publically-available, presented and published technical articles and studies. Although cementing science is well known, getting an effective cement job in the field often requires a large amount of attention to detail. An experienced engineer or foreman can often forecast the quality of a cement isolation step from the cement job’s pump chart recording of density, pump rate, pressure and returns. This type of evaluation is immediately available, requires no added equipment or cost and is superior to most cement monitoring methods of tools on the market, Figure 7.

Figure 7. Upper: Cement pump charts of measurements at each step are one of the best quality checks available on cement. Flow return records can be added check displacement volume. Timing of cement arrival or markers in the returning fluids is an effective indicator of cement fill and mud displacement. Lower: Description of each of the numbered events in the graph. 13 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Testing and/or regular monitoring is required by all states and often mandated for specific areas when detrimental conditions exist. The only proof of isolation continues to be a pressure test, commonly required for all surface strings where fresh water or the surface must be protected. Cement is not always easy to place. A full static column of regular cement, with a density of about 16 lb. per gallon exerts a static force at the bottom of the hole equal to a pressure of 0.83 psi per foot of the true vertical depth (TVD) of the cement column. The amount of pressure generated by the fluid density in a long vertical column of cement may fracture most formations – damaging the rock and compromising well integrity. Lower density cements may still be too heavy to accomplish a full cement column without going to a multi-stage cement job. The required activity of circulating the viscous cement also increases flowing friction backpressure and thus increases its equivalent circulating density – adding another 1 to 2 lb. per gallon density increase that raises the dynamic density of the cement column to as much as 0.94 psi/ft while the liquid cement is circulating. A multi-stage cement job is required to place a full cement column in most wells. The ports in a multi-stage cement placement tool compromise the integrity of the casing and may lead formation of leak paths. Effective cement life is a function of the conditions in the well over its lifetime including the surrounding formation fluids and stresses. Cement can be strong as or stronger than the rock that has provided a seal on gas, oil, and saltwater for millennia. There are records of cemented wells still effectively isolated after one hundred years. Older records for wells are simply not available since the first use of cement in an oil, gas or water well was in 1903 and was not required by newly developed regulatory agencies until about 1915 to 1935. Correct selection and use of additives prevents cement shrinkage, sulfate induced cement deterioration, acid gas reactions, and other detrimental effects.

Wellheads, Christmas Trees, and Flow Equipment After the deepest casing is set and cemented, the blowout preventer used during drilling is replaced by a set of valves that can be used for surface control and routing of pressure and produced fluids. The wellhead, Figure 8, is an intricate control center that uses multiple valves and multiple seal barriers to enable maximum control of fluids flowing from the formation. Two to three barriers are used at most points. Annular access valves may sometimes be below ground level in an accessible cemented cellar. Wellheads and their control systems may be simple on low pressure wells or very complex on high pressure wells, Figure 9. Leaks of oil at surface are rare but gas leaks may be more difficult to detect without regular inspection. The failure rate of properly maintained wellheads is low and is commonly limited to seals that isolate the top of tubulars, seals between the hangers, and valves. Failures in surface barrier systems can be inspected and repaired easily and quickly, usually without exorbitant cost or risk. Failure databases on topside (surface) equipment and some subsurface equipment (e.g. subsurface safety valves) are available through joint industry projects (23). 14 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 8. Wellhead and tree assembly with cut-away of basic casing and tubing string configuration. The design allows maximum flexibility for flow control, monitoring, and quick repair if necessary.

Figure 9. Wellhead on a low pressure gas well (left); a wellhead on a deep, high pressure gas well (right). The layout is similar, but the high pressure wellhead uses twin flow paths to reduce gas velocity and potential erosion as well as giving options for control needed on a high pressure well (12). 15 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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The technology in practice at the time of well construction is a reflection of how well operators and regulators are doing their jobs in applying and checking for use of the best technologies. Early drilling methods such as cable tools allowed blowouts and old-time “gushers”, a once-routine practice that is now happily extinct. Wells completed before about 1903 had a quite peculiar problem – none of them used cement for isolation. Gas simply flowed up the outside of the uncemented steel casing and into the atmosphere. Cementing was introduced in 1903 and was a standard (required) practice by 1920. Rotary drilling, blow out preventers and wellhead designs were in wide use by the 1930’s (4, 9). Effective regulation lagged drilling for years. Oil and gas well drilling in western states was slower to develop while the attention was on the early Pennsylvania oil boom in the 1860 through the 1890’s. The western states benefited from the delay since, by the time the western states oil boom started, cement isolation practices were spreading across the country. California established Plug and Abandonment (P&A) rules in 1915 and Texas in 1919. Few other states with growing oil and gas activities enacted or enforced effective construction and plugging rules. Of the thousands of wells drilled during the first 20 to 30 years in the northeast US, many were not plugged in any way until and unless abandonment regulations orchestrated a systematic approach. In Texas, for example, over 15,000 “orphaned” wells were identified and have been plugged in the past 25 years by the state-run program funded by operator permitting fees (24, 25). Although these plugging programs arrived late in relation to the earliest booms, the application of modern isolation techniques has been a large factor in reduction of pollution potential. There is no doubt that the plugging programs have been improved over the years, but one beneficial outcome is that many, if not most of these old orphaned wells were shallow dry holes or depleted at abandonment and lacked the pressure to flow to surface. Fortunately, most of the wells in North America have been drilled since World War II, and about a third of the wells drilled up to the early 1890’s were dry holes that were plugged immediately after drilling (26). The first unified approach to resource conservation and effective rules to enforce it came in 1935 with the establishment of the Interstate Oil and Gas Compact Commission (IOGCC), the oldest and largest interstate compact in the US that now represents governors of 30 member and eight associated states. The objective of the group is to conserve resources, but also protect the public. Their survey work on idle and orphaned wells has been the driver for most of the well construction and abandonment rules that states have adapted to fit the needs of local geology (26). Well type may be one of the largest factors in well-to-well variances in well failures and risk. Wells that operate at the extremes of temperature, pressure, corrosion tolerance, high erosion potential or are in areas of tectonic induced movement or active subsidence will usually have shorter well life or more integrity problems than wells in less extreme or lower stress environments. Wells must be designed to handle the specific environment, both inside and outside the well, but a better well design includes flexibility to handle operations as field conditions change. 16 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Pressure declines in a well as oil and gas is produced - this usually reduces pollution risk. Three things are required for pollution to occur: there must be a leak path large enough for the contaminating fluid to flow from the source to the target; there must be an undesirable fluid present in sufficient quantity to create contamination; and there must either be sufficient pressure differential toward the target to move the contaminating fluid or a density difference that can move the contaminating fluid. If any of these three elements are removed then contamination from that source will not occur. If a leak path in the casing develops and the hydrostatic gradient of liquid outside the casing (above the producing zone) is higher than the pressure inside, liquid leaks will be into the casing, not out of the casing. Gas wells are not affected in quite the same manner. Although decreased pressure in the gas well diminishes the driving pressure, gas can migrate upward, preserving more of its pressure than a static column of liquid thus the lack of liquid hydrostatic back pressure allows more gas-produced pressure near the surface than would be possible in a well of 100% liquids. Culture of maintenance is a trademark of a good operating company that equates to proper preventative maintenance on the well, such as corrosion inhibitor application, scale inhibition, bacteria control in injected fluids, as well as routine checks and testing. The worst leak rates have been seen on wells with poor maintenance (9).

Well Integrity and Leak Potential Failure frequencies are estimated for wells in several specific sets of environmental conditions (location, geologic strata, produced fluid composition, soils, etc.) (9). Leaks from wells, especially small leaks measured in gallons per day, are difficult to detect. Estimate accuracy depends on a sufficient database of wells with documented failures, divided into: 1) barrier failures in a multiple barrier system that did not create pollution; 2) well integrity failures that created a leak path, whether or not pollution was created; 3) actual events of pollution. Estimated failure frequency comparisons are only valid for a specific set of wells operating under the same conditions with similar design and construction quality. Well age and construction era are important variables. There is absolutely no universal number for well failure frequency. Data from studies of over 650,000 wells worldwide have been examined to give a clearer picture of the leak potential for wells and the difference between a single barrier failure that is contained by the next barrier without leaking and an isolation failure that results from failure of multiple barriers) (9). Older era vertical well leak rates are about 0.02% for this class of wells. The newer class of horizontal multiple fractured wells have a leak rate less than about 0.004% (4 detected liquid leaks in a hundred thousand wells) – this figure continues to be reduced through improvements in design and cementing. Well leakage appears to be influenced by six major factors: geographical location; technology in practice at the time of well construction; efficiency of regulation level and enforcement; well type; pressure; and culture of maintenance (9). 17 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Geographic location may seem an odd factor, but natural seeps are indicative of oil and gas field locations. Large seeps share a common area occurrence with gas or oil fields. Woods Hole Institute explains offshore seep action: “As much as one half of the oil that enters the coastal environment comes from natural seeps of oil and natural gas (27).” Seeps are often found in places where oil and gas extraction activities are also located. As a result, many surface slicks and tar balls caused by seeps are often attributed to releases from oil and gas production activities. Seeps are generally very old and flow at a very low rate, often in an episodic manner. The material that flows out is very often toxic in an undiluted state, but some unique species of organisms are able to use the hydrocarbons and other chemicals released at seeps as a source of metabolic energy. By the time hydrocarbons reach atmospheric conditions, the materials often have become biodegraded by microbial action (27). In areas with high organic content from peat bogs, tundra and areas of heavy plant growth and decaying leaves, the soil will emit much larger amounts of methane than areas like deserts with low amounts of organic carbon.

Studies of Well Failures According a review of state-investigated well pollution incidences in Ohio (185 cases in ~65,000 wells) and Texas (211 cases in ~250,000 wells), the majority of pollution incidents were from drilling, completion, production, waste disposal and wells that were no longer operated but had not been maintained or properly plugged and abandoned (these wells are defined as orphaned wells) (19). The production well problems were dominated by leaks from pipelines and tanks. These data include a significant amount of legacy data before the Texas regulations on pits, cementing and barrier design were changed in 1969. Many of the Drilling and Completion (D&C) incidents were cement isolation problems, some before the cementing regulations were changed in 1969. Fiftyseven of the 75 waste related incidents in Texas during the study period were legacy issues with disposal pits that were outlawed in 1969. Texas has an industry tax funded program that has reduced the number of orphaned wells from 18,000 in 2002 to less than 8000 in 2009, and currently is plugging and abandoning roughly 1000 to 1400 wells per year of the remaining orphaned wells (19).

Barrier and Well Failure Frequency from Case Histories and Databases Using extensive documented literature from several technical societies, Table 2 captures ranges of barrier failures without apparent leaks and well integrity failure (all barriers in a sequence fail) where fluids (oil, gas) may move from inside the well to the outside (contamination/pollution) or from outside to inside the well (intrusion of salt water). Reported leak rates without specific leak path determinations were assumed under worst-case scenario to be leaks rather than barrier failures. 18 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Area / Number of Wells

Number of Construction Failures

Barrier Fail Freq. Range (Containment)

Well Integrity Failure Range (Containment Lost)

Leaks to Groundwater by Sampling

Ohio / 64,830

74 fail initial cement test. 39 failed in production (19).

1983-2007 0.035% in 34,000 wells 0.1% in older wells – worst case.

0.06% for all wells

Detail not available

TX 253,090

10 fail initial cement test. 56 failed in production (19, 28).

~0.02% all wells.

0.02% for older era wells 0.004% for newer wells

0.005% to 0.01% for producers 0.03% to 0.07% for injectors

TX 16,000 horiz-MF

No reported failures (19).

No failure reported

No failure data or pollution reports

No well pollution

MN / 671

Salt creep crush casing (29).

5.5%

Unknown

None reported

Alberta / 316,000

Total vent flow data (30).

No separation data available

4.6% taken as worst case.

No data – mostly gas escape

19

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Table 2. Distribution of Barrier and Integrity Failures — Improvement by Era (Land Wells) (19, 28–30)

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Risk No human or natural endeavors are risk free. The definition of risk includes the recognition that, although there is a degree of risk in every action, the frequency of occurrence and the impact of a detrimental outcome create a risk or threat level that we can understand and accept or reject based on what we believe, hopefully from assessment of facts. For example, actuarial tables of life insurance on pilots and on-board airline staff (showing no elevated life risk from flying in scheduled airlines) and the public’s acceptance of the airlines as a safe way to travel are an educated acceptance of risk. Failure frequency, impact assessment and risk rankings are needed to learn what problems are most important and require rapid attention. Identifying problems without ranking them for frequency and impact is somewhat similar to comparing a large asteroid collision with a tripping hazard created by a wrinkle in the carpet. Both are hazards, but one is catastrophic with a miniscule chance of occurring and few ways to avoid it, and the other is a minor issue, frequently encountered and easily corrected. Impact and frequency are used in every risk-based industry as the basis for preparation, plans, and changes to designs. Effectively improving a process or a design requires identification of the risk producing elements and an assessment of the impact and the probability of an undesirable outcome. For this reason, the actual expression of risk must be made based on a quantitative risk assessment (QRA) and may be compared to other industries where significant risk is an issue (31, 32). The concept of ALARP (As Low As Reasonably Practicable) is widely accepted in risk-based industries and by the public, although many have not heard the term, Figure 10. The ALARP term comes from the United Kingdom and North Sea safety practices and law in the area of safety-critical systems. The basic principle is that the residual risk shall be as low as reasonably practicable, but all endeavors accept a risk threshold that can be described as a judgment of the balance of risk, economic return and social benefit. Within that definition; however, the implied responsibility is that future risk must always be further diminished by applying learnings and developments from study of operations and failures; hence the learning loop in Figure 10. From the study of forces of ruin (wear, corrosion, erosion, decomposition, weather, cyclic loads, etc.) that degrade all things natural and man-made; engineers describe behaviors that will destruct, and design counter-actions that will preserve or extend. An engineered structure, perhaps “perfect” at the time of construction, remains perfect only for a period of time. We “risk” our lives on, but still trust skyscrapers, ships, airplanes, cars, and bridges to perform safely over an expected lifetime. They are designed to have an acceptable, although non-zero, risk levels, as they age or when weather or load conditions change. Lessons of success and failure must enter into both design and maintenance to reduce risk. In engineering design, multiple fail-safe principles and redundant systems are included that both warn of a potential problem and prevent an immediate one. For the oil and gas industry, redundant barriers in well design perform this purpose with great reliability. 20 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 10. ALARP – As Low As Reasonably Practicable diagram showing levels of risk acceptance as zero risk is approached. The learnings loop designation implies that lessons from failures will be incorporated into future designs.

Why Well Integrity Failures Produce Few Pollution Incidents As opposed to loss of control during drilling in high pressure reservoirs, such as the Macondo well, loss of control from completed and producing onshore wells occurs very infrequently for several reasons: •

Many drilling failures are the result of unexpected high pressure or other drilling-related factors where the pressure barriers are mostly dynamic (mud weight and blow out preventer [BOP] or BOP control) and before installation of the full range of permanent barriers in a completed well. The expected frequency of surface releases in production wells (completed wells) is between 10% to 1% of the number expected in drilling (33, 34). Workovers during the life of the producing wells do 21 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

•

raise the risk of a release, although the frequency is still about one-tenth of that during drilling activities (30). Completed wells are constructed of tested multiple barriers - monitored where applicable. Good construction practices followed by good maintenance reduces risk (9).

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As previously stated, pressure inside a producing oil well drops constantly during primary production. As pressure declines, the potential for liquids inside the well to flow to the outside of the well is sharply reduced while the outside fluid gradients above the producing zone maintain pressure, and an inward potential for leaks if a leak path is present.

Age versus Construction Era or Vintage From early failures to “old age” wear, time is portrayed to be the enemy of any engineered structure, regardless of the technical discipline. Although aging is a significant issue, it must be remembered that failures of the past are what our knowledge of today is built upon and, as learnings progress, the failure rates of a later time should be lower than the era before it – this is true in medicine as well as industry activity. Everything we know about success is based on mistakes we have made, but only if we learn from them. A key issue with operators is how they capture and incorporate learnings into the next design. For any risk rating, time is a consideration that cannot be ignored. In well construction, time has at least four major influences: 1.

2.

3.

Time impacts the knowledge available at the time of well construction. This in turn must reflect the knowledge that went into forming the design of the well, the materials available at the time for the construction, and the knowledge-based regulations that governed construction at that time. Failure rates measured in a specific time period are artifacts of that period; they should not be reflective of wells designed and completed later. In oil and gas well construction, the last 15 years have arguably brought more advances (new pipe alloys, better pipe joints, improved coatings, new cements, and subsurface diagnostics by seismic and logging delivering better understanding of earth forces) than the previous fifteen decades of oil and gas operations. Early time failures on new wells reflect both the quality of well construction and general early component failure (similar to items on a new car that must be repaired in the first few weeks of operation). Time reflects the potential for natural degradation of materials and changing earth stresses, both natural and man-made. Structures age; that is inescapable. The impact of aging; however; is highly geographically-variable and controllable to a degree with maintenance. Structures in dry climates and soils often age slowly, while structures in wet areas, salt spray zones, acid soils and tectonically active areas can be degraded and even destroyed in a few years. The oldest producing wells, 22 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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4.

for example, are more than a century old and many have not leaked, while high pressure and high temperature wells (HPHT), thermal-cycled, and corrosive environment wells may have a well life of a decade or less before permanent plugging and isolation is required. Time has also recorded changes in energy source availability from the easily obtainable conventional reservoir petroleum resources to dependence on and development of resources that are much more difficult to access. This, in turn has created technology-driven approaches that have been difficult for some, both inside and outside the industry, to learn and accept.

From the first U.S. gas wells that used wooden pipe (circa 1820s) to a few years after the beginning of the 20th century, zonal isolation of early wells was haphazard at best (9). The first true long-term isolation attempts applying Portland cement in 1903 marked the start of the cemented pipe era (26). The effective two plug cementing system moved cement into a proven isolation technique. Along the way, advances in every well construction technology improved zonal isolation reliability. Major eras of operation and the notable improvements are shown on a timeline in Figure 11.

Figure 11. A timeline of pollution potential by era. Advances in technology, regulation, corporate responsibility, and social pressure have created a lower pollution potential era. Technology advances have driven improvements in wells, often without a clear intent to accomplish that specific goal. For example, rotary drilling made drilling faster but also enabled development of surface pressure control systems that eliminated most blowouts, hydraulic fracturing vastly improved production, but also drove better cementing practices and pipe designs, and horizontal wells reduced the total well count in many areas, thereby sharply lowering any risk of surface and subsurface pollution. While what we know about the past may be accurate (and might not be), any projections we make of the future are estimates, preferably but not always based on our assessment of technology improvement or deterioration of current market trends. After all, how long have we been “running out of oil?” The best forwardlooking estimates must take into account how well the lessons of failures have been 23 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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incorporated into improving the next generation of well designs or development plans. Any development (lakes, tunnels, mines, wells, foundations, etc.) through subsurface strata must consider that every vertical and lateral inch or centimeter of a depositional formation is different from the bit above, the bit below and the bits on each side. The challenge to well design is the need to design for the unknown and the worst load. Well design is a complex geomechanical, fit-forpurpose engineering effort and definitely not a “one-size-fits-all” approach. Wells are designed and built as pressure vessels using exact data on as many variables of the formation and producing conditions as we know and considering how they will change as underground forces are altered by producing or injecting fluids into rocks with fluid filled porosity that have reached equilibrium. This is the challenge that the oil and gas industry has faced for over 150 years.

Hydraulic Fracturing Risks A fracturing study presented in 2012 concluded that risk from fracturing was extremely low, risk from well construction was slightly higher and the real concern was actually transportation and storage of materials (8). Perceived and actual outcomes in Table 3 were researched for frequency and plotted against average impacts in Figure 12.

Figure 12. Risk reduction achieved in hydraulic fracturing by application of developing technology.8 Blue lines are tracks of risk reduction driven by use of safer chemicals, safer methods of transport, and learnings integration back into job designs. Reproduced with permission from reference (8). Copyright 8 George King. 24 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Table 3. Fracturing Risk Events – Event Numbers and Descriptions for Figure 12 1 – spill transport of fresh or low salt water

12 – frac opens mud channel, well < 2000 ft. deep.

2- spill 15 gal biocide

13 – frac opens mud channel, well > 2000 ft. deep.

3 – spill 50 lb. dry non-toxic additives

14 – frac intersects another well in same pay zone.

4 – spill 150 gal diesel from truck wreck

15 – frac intersects properly abandoned wellbore.

5 – spill 2500 gal from refueler wreck

16 – frac intersects improperly abandoned wellbore.

6 – spill frac tank of water, no additives

17 – frac to groundwater through rock, well > 2000 ft. deep.

7 – spill water w/ food grade polymer

18 – frac produces earthquake that can be felt at surface.

8 – spill of 10 gal. diesel during refueling

19 – frac intersects a natural seep.

9 – spill 100 bbls of produced water

20 – frac produces emissions in excess of limits.

10 – frac ruptures surface casing

21 – normal frac operations no problems

11 – cooling pulls tubing string out of packer.

Chemicals Used in Fracturing The identity of chemicals incorporated in fracturing fluids were probably the first thing sensationalized about fracturing. The movie “Gasland” created quite a stir with the statement that a “cocktail” of several hundred toxic chemicals were possibly used in fracturing. The grain of truth was that there are many chemicals in additives sold for incorporation in fracturing; however; the fact is that most fracs use only five to an average of 14 major chemicals and about half of fracturing jobs are “slick water” fracturing fluid that uses from two to five chemicals. Often the chemicals referred to in public objections appeared to included trace amounts of chemicals at the edge of detection and most well below the EPA’s strictest limits. The outcome of the fracturing and well construction studies indicate that transport of chemicals is one of the higher risk areas for well operations. To contrast this risk, a comparison to the larger industrial use of chemicals shows the 4 to 6 billion pounds per year of chemicals transported in peak activity years for hydraulic fracturing amounts to only ~ 0.03 % of all petrochemicals moved by truck and rail in the U.S. in a year. The fraction of fuel used in fracturing is an even small fractional percent of the near 10 trillion gallons of total gasoline and diesel fuels moved on roads and railways. Table 4 shows examples of the most common chemicals used in fracturing, the volumes used and what the alternate uses include. Chemicals such as diesel, 25 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

benzene and proven carcinogens, mutagens and endocrine disruptors are not used in modern safe fracturing fluids.

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Table 4. Examples of Most Common Fracture Additives on Location for a Slickwater or Hybrid Slickwater and Gel Fracturing Job Common Fracturing Additive

Purpose

Type

Avg. Amount Used In A 500,000 Gallon Fracture Stage

Alternate Use

Friction Reducer

Reduce Friction And Pressure During Pumping

High Molecular Weight Polyacrylate Copolymer

100 To 250 Gallons

Absorbent In Diapers, Flocculent For Drinking Water

Biocide

Reduce Corrosion After The Frac

Glutaraldehyde, Quaternary Amines

50 To 100 Gallons

Medical Disinfectants

Scale Inhibitor

Reduce Scaling And Ensure Flow Assurance After The Frac

Phosphonates, Polymers

10 To 50 Gallons

Detergents

Surfactant

Reduce Surface Tension To Improve Oil Production

Alcohol Ethoxylates, Sulfonates

250 Gallons

Detergents

Guar Gum

Increase Viscosity To Carry Proppant

Bio Polymer Made From Guar

300 Gallons

Food Additive

The energy industry is devoting substantial resources to chemistry and focusing on creating new, greener chemical combinations. The chemical producers and companies supplying drilling and hydraulic fracturing services are conducting much of this activity, and energy producers will play an important role in reducing both the volume and the toxicity of the chemicals they use. Smarter chemical use can boost production, cut costs, and reduce environmental impacts. Historically, operators relied on oil field service companies to provide the best technology in compliance, costs, and performance. More recently, many major suppliers have developed ranking systems for rating 26 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

chemical toxicity and are mothballing older products while developing more environmentally sustainable products. Some operators have taken a different tack and created staff positions with chemical industry experience that are responsible for reducing the volume and toxicity of chemicals. Having that chemical industry experience enables operators to use and develop best technology for sustainable cost performance while auditing systems used by service companies. Often, a simple product review can improve sustainability and cost performance and reduce chemical use rates.

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Cutting Chemical Toxicity and Volume The greatest progress in reducing chemical toxicity is occurring with friction reducers, scale inhibitors and surfactants. Biocides and acid corrosion inhibitors have proven more difficult, but new approaches are on the horizon. A few noteworthy developments in reducing chemical volumes and toxicity arise from new technologies for friction reducers and scale inhibitors. Operators are experimenting with replacing liquid friction reducers and scale inhibitors with powdered materials. These powdered materials can reduce the required friction reducers and scale inhibitors volume and reduce carrier solvents and additional chemicals. Powdered materials also will reduce emissions of volatile organic compounds caused by friction reducer and scale inhibitor use. Plus, the lower volume of chemicals will result in fewer trucks on the road, meaning fewer traffic accidents and less carbon emissions. Operators and service companies are developing new technology to reduce the amount of carrier solvents in biocides and surfactants by concentrating the products. As seen with dry friction reducers, this also will reduce chemical volumes, volatile organic compounds and truck emissions and they are using greener carrier solvents. Within hydraulic fracturing, these initiatives have resulted in reducing chemical volume and in using less toxic types of friction reducers, scale inhibitors, biocides, and surfactants. Operator’s progress toward more environmentally friendly hydraulic fracturing is annually reviewed in a report Disclosing the Facts, published by environmental stakeholders from As You Sow, Boston Common Asset Management, Green Century Capital Management, and the Investor Environmental Health Network (35). This report issues a yearly scorecard that ranks companies on disclosure of chemical use, water and waste management, air emissions, community impacts, and management accountability. To further the use of greener chemistry in oil and gas operations many operators and service companies promote industry collaborations. Many have taken leadership roles in a Society of Petroleum Engineers working group on safer chemicals and are active in one of the American Chemical Society’s (ACS) Green Chemistry Institute forums on greener chemicals in hydraulic fracturing. Work in these forums should lead to further reductions in chemical toxicity in the lower volume use areas.These operator and service company groups promote advances 27 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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in chemistry, technical processes, and sustainable chemical with competitive cost performance and their goal is to reduce and eliminate toxic chemical use. The ACS Green Chemistry Institute Hydraulic Fracturing Roundtable has formed as a result. The roundtable is a consortium of operators and service companies that will pool and attract resources to develop more effective and sustainable chemistry for common hydraulic fracturing needs. The ACS Green Chemistry Institute chairs roundtables in four chemistry related industries with high sustainability profiles in terms of products and volumes. Operators are improving on being as transparent as possible in disclosing carbon, water, and chemical data. Many operators disclose greenhouse gas emissions and water usage to the Carbon Disclosure Project (CDP), an online international disclosure collaboration (36). Operators also make a significant effort to post comprehensive chemical disclosures for all hydraulically fractured wells from our U.S. operations on the FracFocus website, which is operated by a federally charted Interstate Oil and Gas Compact Commission and the Groundwater Protection Council (37). In Canada, they post similar material on the FracFocus.ca website, which is maintained by Canadian authorities for wells in British Columbia and Alberta (38). In July 2013, FracFocus.org was technically upgraded to allow operators to post water volumes by source type, so for postings since July 2013 the company is detailing the amount of water that comes from freshwater resources, brackish groundwater or recycled produced water on a well-by-well basis. On the FracFocus.org site, disclosures are keyed to geographical coordinate systems and instantly appear on Google maps. Authorities and reporting agencies have the capability of gathering and analyzing information on any data set. Any user can easily determine what has happened in a specific well or area of concern. Operators may also work with service companies and chemical vendors on a continuous basis to minimize use of chemicals overall and to select hydraulic fracturing fluid additives that minimize environmental or health concerns. Full disclosure of chemical additive compositions may be disclosed in many cases but the exact formulation (proportions of chemicals) is often not available to operators. Operators attempt to disclose 100 percent of all deliberately added chemical additive components whenever possible. Some vendors and chemical suppliers maintain legal rights granted by state or federal authorities to protect intellectual property and refuse to fully detail additive compositions; however, operators must maintain active management oversight of all operations and can specify toxic or dangerous chemicals such as benzene, toluene, ethyl benzene, and xylene (BTEX), endocrine disruptors, mutagens, carcinogens, etc. that they will not allow to be used in their wells. Each specific area has internally reviewed operational procedures since geological variability of areas that will require different additive formulations. The use of more toxic chemicals is decreasing and acceptable substitutes and making solid headway in replacing the older chemicals but care is still required. Operators also work with major service companies to pioneer the use of large-scale natural gas fueled engines in our well-site operations that mitigate air emissions. 28 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Reduction Strategies Operators and service companies work to lower chemical volumes, reduce chemical toxicity and improve environmental fate, which is the destiny of a chemical after its release to the environment. Reduction strategies include: • • •

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• •

reducing overall chemical volume; reducing volatile organic compound emissions; reducing chemical component toxicity, including the elimination of high risk chemicals (e.g., diesel, BTEX, endocrine disruptors, and carcinogens); cutting back on total chemical volumes and lowering the chemical volumes hauled by trucks; and improving usage strategies, including using chemical components that are less bio-accumulative and more biodegradable.

Generally, chemicals used in hydraulic fracturing fall into five categories. • •

• •

• •

Biocides: Disinfectants that kill down-hole bacteria that can corrode pipes. Friction reducers: Chemical compounds that "slick the water" to minimize friction and pressure. These compounds allow the fluid to carry more sand into the fractures, making them wider and more permeable to produce more oil and gas. Gel systems: Different than friction reducers, these chemical compounds increase viscosity of water to allow it to carry more sand into the fractures. Scale inhibitors: These compounds keep mineral scales such as calcium carbonate and calcium sulfate from forming in pipes, which can slow oil and gas flow. Surfactants: Detergents that help wash out contaminants down hole so the well can yield more oil and gas. Acid additives: Additives used during the acid job used in each stage.

These and other chemicals are used in minute amounts as additives during hydraulic fracturing. Water and sand make up 98 to 99.5 percent of a slickwater hydraulic fracturing fluid, with the exact formulation varying from well to well.

Review of Additive Use and Progress Made on Additive Toxicity Reduction Slickwater, gel fracturing fluids and hybrid mixtures of the two are the most common fracturing fluids. Fracturing fluids must create a fracture in the rock and then must carry a proppant like sand into the fracture to preserve the flow path that the fracture creates. Efforts to produce “greener” fracturing fluids have led to many advances on fracturing chemicals for lower toxicity. 29 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Friction Reducers (FR) Green Progression - (FR) Slickwater Frac Fluid

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•

Emulsion Polymers – high molecular polyacrylates with slightly anionic character materials are the currently used compounds but dry powdered materials with no oil phase and no surfactants that have one-third the volume, volatile organic compounds (VOC) and risk are being developed with a lower cost. These are also U.S. Environmental Protection Agency - Design for Environment (EPA-DFE)-listed and drinking water approved (39).

Gellants – Guar/Hydroxyl Ethyl Cellulose/Crosslinkers/Gel Breakers – Gel Frac Fluid •

Crosslinkers, which were metal ions have given way to greener borate materials. Gel breakers, typically persulfates, peroxides, etc. have acute toxicity but short lived with rapid spending and non-toxic by-products. Reducing gellants reduces the need for breakers. Guars, either natural or modified are inherently green with good biodegradation properties.

•

•

Biocides Biocides are used in slickwater applications to prevent bacteria growth and must be safe, cost effective, be compatibility with other additives.

Biocides Green Progression • •

•

•

Early products - THPS, DBNPA, bromine based biocide , TTPC, halogenated oxidizers – now considered inferior for oilfield use. Current - Glutaraldehyde or glutaraldehyde and quaternary amine mixture – North Sea Gold Band rated with great cost performance, friction reducer compatibility. In some cases, ultraviolet light is used as a bacterial control and other mechanical methods are under trial. On the horizon - Nitrogen reducing, sulfate oxidation (NRSOB) Bio exclusion technology - Borderline commercial and successfully trialed in Marcellus Shale and Permian in the Wolfcamp Future - Phage Bio Control – Experimental in Oilfield - Studies underway for Health, Food Safety, Veterinary, Agriculture, Aquaculture, Fermentation industries

Scale Inhibitors Calcium sulfate, calcium carbonate and barium sulfate can cause scale flow assurance problems in the well. As the well is fractured, water dissolves minerals 30 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

in the formation, and scale can form if the conditions are right. Most available scale inhibitors are phosponates and polymers which are anionic.

Scale Inhibitors Green Progression (SI) • •

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•

Past and still in use - Phosphonates – DETA / Amine – N/P containing formulated in methanol More current - Polymers – low molecular weight polymers – lower toxicity although still formulated methanol or ethylene glycol. Now available - Dry Polymers - 1/8th the volume, 1/3rd the VOC, 1/3rd the logistics risk and lower cost. Also EPA-DFE listed

Surfactants The major use of surfactants in hydraulic fracturing are listed below: • • • • • •

Assist in FR inversion via surface tension reduction. Sacrificial water wetting of sand vs. friction reducer adsorption. Non-emulsifying properties for fluids entering perforations (perfs) at high shear rates Lower surface tension to aid in fluid traveling through sand pack Reduction of relative perm damage due to ingression of frac fluids into pore spaces Dispersion of natural wax , asphaltenes, maltenes, etc.)

Surfactants Green Progression • • •

•

Past materials - BTEX Solvent based Older approach - Cationics – oxyalkylated amines / quats in water based + methanol – poor compatibility with FR Current - Non ionics – oxyalkylated alcohols in water based + methanol; anionics – sulfonates in water based + methanol; Non ionics / Sulfonates in water base + isopropyl alcohol (IPA)/ propylene glycol - no oil phase, less VOC, lower RM cost - EPA-DFE listed components Frac jobs typically start with a small acid job to dissolve near well bore formation and excess cement to ensure that the perfs are clear for the frac stage. The additives for this acid job include corrosion inhibitors and surfactants. The surfactants are similar to the surfactants used in the frac fluid itself.

Acid Corrosion Inhibitor Green Progression •

Past products - Acetylenic organics – propargyl alcohol + Alkly pyridine quats 31 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

• •

Fatty amines / Fatty amine quats Greener acid corrosion inhibitors have been developed and are in use in the US.

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Groundwater and Methane Migration Groundwater, brine zones and produced water from oil and gas operations in a specific area do not have a constant composition (40–42). Variability in any groundwater is well documented (40, 41). Causes of natural variation in mineral and methane content in ground water and brine zone include: seasonal variance, barometric pressure changes, changes produced by runoff, water recharge routes into the reservoir, recharge sources, recharge rates, depth of water withdrawal and rate of groundwater withdrawal. According to groundwater experts, overdrawing or over-drafting a groundwater reservoir (withdrawing water faster than it can be recharged) can produce notable changes in the reservoir water composition including pulling contaminants in from above and salt from below. This variability makes single point comparisons of water quality practically worthless. Many fresh groundwater aquifers are laterally or vertically connected to more saline water sources. Salinity, within a single unit, often varies with depth. Sudden changes in pressure within a groundwater reservoir will also change the amount of free methane gas by causing gas to move from solution into free gas phase (44). The only way to assess changes in a groundwater source is to establish a trend range and include seasonal variations, withdrawal rate and other variables. Investigations of stray natural gas incidents in Pennsylvania reveal that incidents of stray gas migration were not caused by hydraulic fracturing of the Marcellus shale (45, 46). The possibility of some gas migration events being related to drilling cannot be dismissed, since air drilling, when practiced, may be a cause for temporary upsets in shallow well water color and odor, although the worst of these migrations appear to be in areas with known history of shallow gas flows that predate drilling (47). Methane is the most common gas in groundwater. Shallow methane may be from sources both thermogenic (maturation of depositional organics in the reservoir) and biogenic (biological breakdown of organic materials carried into the reservoir). Depending on the area of the country and the specifics of the aquifer, groundwater, fresh or saline, may dissolve and carry methane gas in concentrations of 0 to 28 mg/l. Free (non-dissolved) methane gas exists in many aquifers under the caprock or in rock layers and methane gas is frequently desorbed from organic formations such as coal or shale as the pressure is reduced by producing the water from these formations. As water flows out of a rock formation and into a wellbore, pressure is lowered, creating opportunity for some dissolved methane gas to move out of the water and become a free gas phase (similar to the CO2 escaping as a fresh bottle of carbonated soda is opened). Higher draw-downs will enable more gas to come out of solution (similar to rapidly pouring any carbonated beverage). Any free gas will rapidly rise in the water well and can accumulate into the highest part of the well piping system, and, if not vented by proper water well construction, will follow the moving 32 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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water when the water tap is opened in the house. This is the cause of burnable gas seen in 200 year old historical reports on igniting water wells and in more recent dramatic TV and movie shots of burnable gas quantities in faucets and garden hoses. If the well is constructed correctly, a vent cap allows the methane to escape from the well and prevents most gas accumulation. The frequency of gas appearance in groundwater is linked to a number of factors, most of which can be more geographically or geologically influenced than impacted by oil or gas well presence. Figure 13 shows a number of these factors as positive or negative influences. Perhaps surprisingly, many of the influences are natural in origin. Wells, particularly those drilled with air, can play a significant local role in gas migration disturbances (46) either by air charging shallow water sands or by displacing shallow pockets of methane into the low pressure areas caused by groundwater withdrawal. The number of water supply wells drilled in the U.S. is near 15 million, not counting those that have been dug, driven, or drilled and then abandoned without being reported (48). There are very few mandatory water well standards enforced in the U.S. and improperly constructed, poorly maintained, and improperly abandoned water wells can be a primary pathway for aquifer contamination by a variety of materials, both from surface and subsurface inflow, regardless of the source of the gas.

Figure 13. Factors involved in gas migration may include natural sources as well as both water well construction and gas well construction or abandonment.

Methane Emissions In the past decade methane has been reported by some forward projecting models to be a more serious Greenhouse gas than originally thought with leak potential along section of the vertical part of the casing and through the annulus. Routine methane venting has been stopped on flowbacks and equipment is 33 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

being designed for more effective controls of methane released from pneumatic control devices, compressors, and other operations that currently vent even small amounts of methane. Green completions, although not yet specifically designed, are evolving towards zero gas emissions.

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Major Sources of Pollution – Where Do Oil and Gas Wells Rank? Groundwater pollution continues to be a major issue in the U.S.; but what are the primary causes and pathways? The indisputable major sources of U.S. groundwater contamination over the past few decades are: 1) leaks from underground storage tanks (gasoline, diesel, and chemicals) at filling stations and industrial sites with buried tanks, 2) improper residential septic systems, 3) agriculture waste and runoff of pesticides and fertilizers, and 4) poorly constructed landfills (Figure 14) (49).

Figure 14. EPA data collected in 1999 from states, tribes, and territories on reported incidents of groundwater pollution. Reproduced from EPA 2000 National Water Quality Inventory. Reproduced with permission from reference (49). Copyright 2000 U.S. EPA.

Case History – Texas Aquifers, Oil and Gas Wells, and Pollution To update the potential of groundwater contamination in a high density oil and gas well environment, data from Texas Commission on Environmental Quality (TCEQ) and Texas Groundwater Protection Council (TGPC) pollution 34 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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reports were reviewed for specific references to reported oil, gas, and injection well relevance (28, 50). The state of Texas, where half of the U.S. fracturing and nearly half of the U.S. drilling rigs operate, was used as an example, specifically to examine reports of pollution in high density oil and gas well areas on a county-by-county basis. The major aquifers of Texas, overlaid with hundreds of thousands of oil and gas wells drilled through those aquifers are mapped in Figure 15 (51). Studies of pollution reports from counties show a higher correlation of oil and saltwater pollution in surface facilities (plants, compressor stations, and tank storage), but few direct downhole results linked to producing wells (28). Roughly 80% of groundwater withdrawals in Texas are used for agriculture and municipal water supply. Aquifers of varying water quality and quantity underlay between 80 to 90% of Texas lands. Reports of water quality from properly built water supply wells affecting public health or crops are rare.

Figure 15. Overlay of oil and gas wells over areas of Texas major aquifers. Adapted with permission from reference (51). Copyright 2011 Texas Water Development Board. Pollution report records for Texas were examined for major causes of pollution and for possible links to oil and gas wells. The reported pollutant frequency information (volumes of pollutant released were not available) from the 35 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Texas Railroad Commission (TRC) and the TCEQ, Figure 16, shows decreasing pollution report frequency from 2000 through 2011 (last available data). The biggest pollution report was from underground gasoline and diesel storage tanks at filling stations, and variable exposure to manufacturing chemicals, solvents, waste oils, and very small incidents of spills involving road transport of oil (28).

Figure 16. Reported Incidents of Groundwater Pollution in Texas from TCEQ records. The top twenty reports on pollution were predominantly caused by leaking fuel tanks from filling stations, improper disposal of dry cleaning solvents (chlorinated materials), various metals (possibly from metal plating/treating operations) and agriculture sources. The percentage of pollution reports that TCEQ and TGPC identified as under TRC authority varied between less than 1% to a maximum of about 10% of the total new pollution reports each year (28). Further analysis of these reports showed a breakdown of cases where surface facilities (tanks, separators, gas plants, compressors, and gathering lines), and pipelines were responsible for about 90% of the fraction of pollution incidents where TRC had jurisdiction. The remaining reports of pollution, roughly less than 1% of the total reported each year, concerned the 200,000 to 250,000 wells that are producing, injecting or shut-in in Texas during the respective time period. All leaks were ascribed to wells whether they had been investigated or not – a worst-case approach. No leaks from abandoned wells were listed, although these may have been addressed 36 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

under the Texas Orphan well program which ranks and then plugs and abandons over 1400 wells per year.

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Naturally Occurring Radioactive Materials (NORM) Many areas of the country are listed as higher than average radioactivity, with solar and natural background being the most prevalent natural radiation sources and radon gas being the most serious health risk. Medical radiation sources (gastrointestinal series, diagnostic x-rays and mammograms) are significantly higher than common well or industry sources, and produced fluids from most wells was significantly below that of cosmic radiation. The level of NORMs found in produced water from oil or gas wells varies considerably across the country but all is reportedly lower than EPA acceptable levels unless the materials are concentrated (filtering, evaporating, scaling, precipitating or in sludges). Some older oilfield produced water handling facilities will occasionally produce deposits of NORM materials although the volumes and activity is usually low.

Water Use About 99% of the all the fluid volume used for fracturing is water but water used in fracturing is rarely over 1 to 2% of the total water used in states where fracturing is practiced. Nation-wide, fracturing may use about 100 billion gallons of water in a year (combined fresh and salt water). Although a seemingly large volume, the water usage for fracturing pales by comparison to yearly volumes used in thermo-electric power generation, irrigation and domestic fresh water usage, Figure 17. Power generation, which uses significant amounts of surface water as well as groundwater, is a single-pass through use of water with most returning water released to surface flowing water, regardless of whether the initial source was surface or groundwater. Compare this to the estimated 2.08 billion gallons of water used per day for golf course irrigation in the U.S. (51) In comparison, just the leakage from America’s residential and industrial fresh water supply lines is estimated at almost 6 billion gallons per day and 2.1 trillion gallons per year (52). Fracturing supply water sources are surface water, fresh water wells, salt water from oil field produced water and other concentrated brines. The high salt content waters now widely used in fracturing are unusable for agriculture and have too much salt reject to make reverse osmosis units economical. The amount of recycling of produced and salt waters and the use of high total dissolved solids (TDS) brines varies with the cost of and availability of fresh water and the cost and availability of disposal or treating of produced water. The volume of fresh water used for fracturing in Texas, where half of the hydraulic fracturing jobs in the U.S. are pumped, is about 1 percent of the total water usage for the state as a whole, but may range higher than 10% of the available water supply in a localized area. Although this volume may appear low for the state, dry areas may not be able to sustain this usage volume. This has been a driver for produced water recycling in Texas. 37 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 17. Total freshwater use in the U.S. from USGS estimates for 2010. Reproduced with permissions from reference (54). Copyright 2014 United States Geological Survey. Water usage for production of primary fuels is shown in Table 5 (54).

Table 5. Gallons of Water Used by an Energy Source to Produce 1 Million BTUs of Energy Primary Energy Resource

Range of gallons of water used per million BTU generated

Data Source

Natural Gas (based on all water needs for gas from shales including fracturing)

1 to 3 (conventional gas uses less than shale gas development)

USDOE 2006, P59.

Coal (no slurry transport) (with slurry transport)

2 to 8 13 to 32

USDOE 2006, p53-55.

Nuclear (processed uranium ready to use in plant)

8 to 14

USDOE 2006, p 56.

Conventional Oil

8 to 20

USDOE, p 57-59.

Synfuel Coal Gas

11 to 26

USDOE, p 60.

Oil (liquid) from shale

22 to 56

USDOE, p 57-59.

Oil from Tar Sands

27 to 68

USDOE, p 57-59.

Ethanol (irrigated corn)

2510 to 29,100

USDOE, p 61.

Biodiesel (irrigated soy)

14,000 to 75000

USDOE, p 62.

The low volume of water required to produce natural gas using fracturing technology makes it one of the most water–efficient primary fuels.

38 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Induced Seismicity - Earthquakes No earthquake under your house is ever “small”, but thousands of tremors occur each year around the world, so what is the seismic risk from natural or manmade activities and what can minimize the occurrence and impact? Creating a large seismic event requires a certain set of geologic and stress conditions and the depth (also called hypo-center or “focus”) is most often along deep tectonic plate margins that are subject to “stick and slide” behavior. Large quakes are also possible in areas away from the major tectonic boundaries along fault lines, such as the New Madrid Fault of the central U.S. Induced seismicity, that fraction of seismicity resulting in part from man’s activities, is a reaction to loads and forces resulting from creation of surface impoundments of water (creating lakes), removing or piling up hundreds of millions of tons of rocks and soil (strip mining) and injection of fluids into some subsurface rocks that are highly stressed and capable of movement (produced water disposal). Not every activity will create tremors; the conditions to create a shift in the rock strata must be ready and waiting for the extra push to create fault movement. Highly damaging earthquakes, those of Magnitude 7 or higher have occurred in a few, very specific places in the U.S., usually along tectonic plates or major faults (56). According to the USGS: “The magnitude of an earthquake is related to the length of the fault on which it occurs -- the longer the fault, the larger the earthquake. The San Andreas Fault is only 800 miles long. To generate an earthquake of 10.5 magnitude would require the rupture of a fault that is many times the length of the San Andreas Fault. No fault long enough to generate a magnitude 10.5 earthquake is known to exist. The largest earthquake ever recorded was a magnitude 9.5 on May 22, 1960 in Chile on a fault that is almost 1,000 miles long”. Large magnitude earthquakes usually rip open hundreds of miles of faults, often creating ground shifts and “ground waves”. The short duration of hydraulic fracturing simply does not have the capacity to create this level of energy. However; very large-volume water injection has been identified as a culprit in a few hundredths of one percent of the US’s 150,000 UIC-II (oil & gas injection and produced water disposal wells). Fracturing, particularly near the larger faults within a pay zones have produced felt quakes with magnitudes of 1.0 to 3.0 and higher. Certain regions such as central Oklahoma have seen much higher earthquake activity related to very large volume disposal from produced water. Determining the strength (magnitude), the surface location (epicenter) and depth (hypocenter or focus) are becoming better with time because of the increase of monitoring stations from the few hundred stations worldwide in the 1930’s to the tens of thousands of monitoring stations today. Closer station positioning results in sensing and locating more of the small quakes that were previously undetected. The earthquake risk maps for the US have shown small changes in some areas, Figure 18 (57, 58). Increased numbers of monitoring stations and use of portable monitoring stations has helped redefine most areas of risk. Note that risk has increased in a 39 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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few areas such as central Oklahoma where induced seismic from injection wells is suspected and fault mapping has identified higher risks.

Figure 18. USGS Earthquake Risk maps of 2008 and 2014. Maps showing peak ground acceleration for 2% probability of exceedance in 50 years and Vs30 site condition of 760 m/sec. Reproduced with permission from reference (57). Copyright 2014 USGS Earthquake Hazards Program.

Recycling Produced Water A better approach to water disposal, with multiple benefits, is to consider recycling the produced water into fracture base fluid. Recycling produced waters relieves pressure on fresh water supplies and can sharply reduce the volume of water that is sent to disposal wells. A workable approach was advanced by Apache Corporation in several southwest US areas (20, 59). Hydraulic fracturing stimulation in one area of concentrated well development utilized a mixture of recycled produced water and a feed stream of high salinity groundwater that was not suitable for agriculture use. In 2013, sixty-two new horizontal completions in the area used a total of 12.8 million barrels (bbls) of water for operations that was approximately 75 percent brackish and 25 percent recycled produced water (55). In the first three months, there were 18 new horizontal completions, using a total of 5.0 million barrels of water (49 percent brackish, 51 percent recycled). Each hydraulic fracture requires approximately 200,000 to 300,000 bbls of water per well (8.4 to 12.6 million gallons). The total volume of water produced from the field is approximately 32,000 bpd (barrels per day), varying from 100 to 2,500 bpd per well. Eighty percent to 100 percent of the water used for the hydraulic fracture is produced over the life of each well. In this area, the recycled and brine combined waters satisfied 100% of the 12 million barrel (537 million gallon) fracturing water demand without using any fresh water.

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19. Kell, S. State Oil and Gas Agency Groundwater Investigations and Their Role in Advancing Regulatory Reforms, A Two State Review: Ohio and Texas, August 2011. Ground Water Protection Council. https://fracfocus.org/sites/default/files/publications/state_oil__gas_ agency_groundwater_investigations_optimized.pdf (accessed July 15, 2015). 20. King, G. E. 60 Years of Multi-Fractured Vertical, Deviated and Horizontal Wells: What Have We Learned; SPE 170952; SPE Ann. Tech. Conf. Amsterdam, The Netherlands, October 27−29, 2014. 21. Bachu, S.; Watson, T. Possible Indicators for Potential CO2 Leakage along Wells; Proceedings of the 8th International Congress on Greenhouse Gas Control Technologies; Gale, J., Rokke, N., Zweigel, P., Svenson, H., Eds.; Elsevier, 2006; CD. 22. Bachu, S.; Watson, T. Review of Failures for Wells Used for CO2 and Acid Gas Injection in Alberta, Canada; Proceedings of the 9th International Conference on Greenhouse Gas Control Technologies, Washington, DC, November 16−20, 2008, Elsevier, Energy Procedia, Vol.1, no. 1, p 3531−3537, 2009. 23. Sintef, Well Integrity, April 2010. PDS Data Handbook, 2010 ed. http:/ /www.sintef.no/upload/Petroleumsforskning/Brosjyrer/Well_Integrity.pdf (accessed July 23, 2015) 24. Plugging and Abandonment of Oil and Gas Wells; Paper 2-25; NPC; Prepared by the Technology Subgroup of the Operations & Environmental Task Group, September 5, 2011. 25. Thomas, K. Produce or Plug? A Summary of Idle and Orphan Well Statistics and Regulatory Approaches; SPE 68695; SPE/EPA/DOE Exploration and Production Environmental Conference, San Antonio, TX, U.S.A., February 26−28, 2001. 26. Calvert, D.; Smith, D. Issues and Techniques of Plugging and Abandonment of Oil and Gas Wells; SPE 28349; SPE Annual Technical Conference and Exhibition, New Orleans, LA, U.S.A., September 25−28, 1994. 27. Natural Oil Seeps. Woods Hole Oceanographic. http://www.whoi.edu/main/ topic/natural-oil-seeps (accessed September 24, 2015). 28. Annual Reports: Managing Nonpoint Source Water Pollution, Reports from Years 1997 to 2011. Texas Commission on Environmental Quality. http://www.tceq.texas.gov/waterquality/nonpoint-source/mgmt-plan/annualreports.html (accessed July 28, 2015). 29. Clegg, J. Casing failure study – Cedar Creek anticline. Soc. Pet. Eng. J. Pet. Technol. 1971, 23 (06), 671–684. 30. Watson, T.; Bachu, S. Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores. Soc. Pet. Eng. Drilling and Completions 2009, 24 (01), 115–126. 31. Oakley, J. Using Accident Theories to Prevent Accidents; 05-534; ASSE Professional Development Conference and Exposition, New Orleans, LA, U.S.A., June 12−15, 2005. 32. Martland, R.; Mann, P. Examining The Sustainability of E&P Major Accident Prevention Design Principles in A Changing Global Environment and Comparisons With the Rail, Nuclear and Aviation Industries; SPE 156910; SPE/APPEA International Conference on Health, Safety, and Environment in

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48. Groundwater Facts. National Groundwater Association. http://www.ngwa.org/ fundamentals/use/pages/groundwater-facts.aspx (accessed July 22, 2015). 49. National Water Quality Inventory, 2000, Chapter 6, Ground Water, Figure 6-5, p 52. EPA. http://water.epa.gov/lawsregs/guidance/cwa/305b/ 2000report_index.cfm (accessed July 29, 2015). 50. Maps: Major Aquifers. Texas Water Development Board. https:// www.twdb.texas.gov/mapping/doc/maps/Major_Aquifers_8x11.pdf (accessed July 28, 2015). 51. Joint Groundwater Monitoring and Contamination Report – 2011; SFR-056/ 11; Texas Groundwater Protection Committee, August. http://tgpc.state.tx.us/ groundwater-information/ (accessed July 29, 2015). 52. 2005 Golf’s Use of Water: Solutions for a More Sustainable Game. USGA. http://www.usga.org/articles/2012/11/golfs-use-of-water-solutions-for-amore-sustainable-game-21474851056.html (accessed February 9, 2015). 53. The Case for Fixing the Leaks: America’s Crumbling Water Infrastructure Wastes Billions of Gallons, Dollars. CNT. http://www.cnt.org/2013/11/18/thecase-for-fixing-the-leaks-release/ (accessed February 9, 2015). 54. Maupin, M. A.; Kenny, J. F.; Hutson, S. S.; Lovelace, J. K.; Barber, N. L.; Linsey, K. S. , Estimated Use of Water in the United States in 2010; U.S. Geological Survey Circular 1405, 2014. http://dx.doi.org/10.3133/cir1405 (accessed July 29, 2015) 55. Younos, T.; Hill, R.; Poole, H. Water Use Efficiency of Energy Production and Power Generation Technologies, 2010. Ground Water Protection Council, Virginia Tech. http://www.gwpc.org/sites/default/files/event-sessions/ FP_Younos_Tamiim.pdf (accessed November 6, 2014). 56. USGS Magnitude 7 and Greater Earthquakes in the United States. http://earthquake.usgs.gov/earthquakes/states/large_usa_7.php (accessed February 16, 2015). 57. Petersen, M. D.; Moschetti, M. P.; Powers, P. M.; Mueller, C. S.; Haller, K. M.; Frankel, A. D.; Zeng, Y.; Rezaeian, S.; Harmsen, S. C.; Boyd, O. S.; Field, N.; Chen, R.; Rukstales, K. S.; Luco, N.; Wheeler, R. L.; Williams, R. A.; Olsen, A. H. Documentation for the 2014 Update of the United States National Seismic Hazard Maps; U.S. Geological Survey Open-File Report 2014-1091; ISSN 2331-1258 (online), first posted July 17, 2014. http://dx.doi.org/10.3133/ ofr20141091 (accessed February 16, 2015). 58. Lower 48 Maps and Data, 2014. USGS Earthquake Hazards Program. http://earthquake.usgs.gov/hazards/products/conterminous/ (accessed July 29, 2015). 59. Barnes, C.; Marshall, R.; Mason, J.; Skodack, D.; DeFosse, G.; Smith, D.; Foreman, S.; Hanna, T.; Cecchini, M. The New Reality of Hydraulic Fracturing: Treating Produced Water Is Cheaper than Using Fresh; SPE 174956; Presented at SPE, Houston Texas, September 28−30, 2015.

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Chapter 2

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Securing the Benefits: A Balanced Approach to Hydraulic Fracturing and the U.S. Emergence as a Global Energy Superpower Erik G. Milito* American Petroleum Institute, 1220 L Street, N.W., Washington, DC, 20005, United States *E-mail: [email protected]

The technologies of hydraulic fracturing and horizontal drilling have elevated the United States (U.S.) to global prominence as an energy superpower. Because of the advanced application of these technologies, the United States is now the world’s largest producer of natural gas and could soon become the world’s largest producer of crude oil. This energy revolution has helped to energize the U.S. economy by driving domestic investment in energy projects, creating jobs, and enhancing U.S. energy and national security interests. This shift in the U.S. energy paradigm has successfully occurred through a balanced approach that secures these vital economic and societal benefits while protecting workers, the public and the environment. Safe and environmentally responsible development of U.S. resources has occurred largely through the application of industry best practices and standards that apply before operations begin and continue all the way through production and abandonment of the well site. This chapter will provide an overview of industry standards in place to ensure safety and environmental protection for purposes of unconventional resource development, including hydraulic fracturing operations.

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“The U.S. Is an Energy Superpower” The headlines say it all. On June 9, 2012, Daniel Yergin, Vice Chairman of IHS and Pulitzer Prize winning author of The Prize, declared and described “America’s New Energy Reality” in The New York Times. As Yergin put it, “energy independence was a subject to get laughs. The joke was that America was actually becoming more and more dependent upon imports. But now ‘energy independence’ has become a subject of serious discussion and debate (1).” Then, just over a year later on October 3, 2013, the front page of the Wall Street Journal pronounced “U.S. Rises to No. 1 Energy Producer.” This headline was based upon the news that the U.S. surpassed both Russia and Saudi Arabia as the largest producer of petroleum and natural gas hydrocarbons in 2013. The Journal referred to this changing energy paradigm as “a comeback fueled by shale-rock formations of oil and natural gas that was unimaginable a decade ago (2).” The Journal highlighted a quote from Energy Information Administration (EIA) Administrator Adam Sieminski who said “This is a remarkable turn of events. This is a new era of thinking about market conditions, and opportunities created by these conditions, that you wouldn’t in a million years have dreamed about (2).” Then, just one day later, on October 4, 2013 Time magazine ran the headline that sums it up best -- “The U.S. Is an Energy Superpower.” And almost simultaneously with the Time and Journal pronouncements, to underscore the true force of the reemergence of the U.S. as an energy superpower, Investor’s Business Daily ran an online editorial on October 3rd with the heading “U.S. Fracking Success Threatens Russian Economy, Strategy.” It has become abundantly clear that the benefits of this U.S. energy revolution are real and dramatic, and run the gamut from job creation to government revenue generation to consumer savings to the promotion of U.S. national security. The energy boom owes its success to uniquely American engineering ingenuity behind the cost-effective application of hydraulic fracturing combined with the rapid development of horizontal drilling at increasing depths. The use of these engineering technologies has fueled the U.S. energy renaissance by allowing effective and increasingly affordable access to low porosity and low permeability oil and natural gas bearing shale and sandstone formations, referred to as “tight formations.” The U.S. has abundant supplies of tight oil and gas resources, and it is through the productive application of these two technologies that the U.S. has become the largest producer of natural gas and is projected to become the largest producer of crude oil within the next few years. Without hydraulic fracturing, the U.S., and the world, would be in a world of hurt, with far less available supplies of oil and natural gas, far less jobs, far less government revenues, far less disposable income, and far greater national security risks. While hydraulic fracturing is not a new technology – it was first applied commercially in 1949 – it has become a prominent topic of debate in policy circles, with questions raised about potential adverse impacts from the use of the technology. Fortunately, through a balanced approach, the U.S. is well positioned to both harness the tremendous benefits flowing from the use of hydraulic fracturing and ensure the protection of the environment. This has been made quite evident, and in many respects proven, through the industry’s development and implementation of standards and best 46 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

practices for operations utilizing hydraulic fracturing. This chapter will focus on the benefits derived through the deployment of hydraulic fracturing and on the standards developed to ensure continued responsible development through the use of hydraulic fracturing for decades to come.

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Hydraulic Fracturing From a technical standpoint, hydraulic fracturing is defined as “injecting fracturing fluids into the target formation at a force exceeding the parting pressure of the rock thus inducing fractures through which oil or natural gas can flow to the wellbore.” This definition is provided in API Guidance Document HF2, Water Management Associated with Hydraulic Fracturing, First Edition, June 2010. The Department of Energy provides a more detailed description as follows: Hydraulic fracturing is a means of creating fractures emanating from the well bore in a producing formation to provide increased flow channels for production. A viscous fluid containing a proppant such as sand is injected under high pressure until the desired fracturing is achieved. The pressure is then released allowing the fluid to return to the well. The proppant, however, remains in the fractures preventing them from closing (3). It is this technology, combined with precision guided, steerable horizontal drilling, that is responsible for catalyzing America’s energy future. While recent advancements in hydraulic fracturing and horizontal drilling have made this American energy revolution possible over a relatively short period, the fundamental technology of hydraulic fracturing has been in commercial use since 1949. In fact, the story of hydraulic fracturing takes us much further back to the early days of the oil and natural gas industry. Since the drilling of the original Drake well more than 150 years ago, it became readily apparent that we have “good rocks” here in the U.S. In other words, we have tremendous geological deposits of oil and natural gas trapped below our feet all across the country. The engineering challenge confronting petroleum geologists and engineers since the drilling of that first Drake well has been fairly straightforward: How can you most effectively free the oil and natural gas from these good rocks and get it to the surface for economic use? As reported in an Energy Tomorrow Blog by Mark Green of the American Petroleum Institute on March 17, 2014, in a 2010 piece in the Society of Petroleum Engineers’ Journal of Petroleum Technology (JPT), Carl Montgomery and Michael Smith describe efforts in the 1860s to engage in “shooting” operations intended to “rubblize” the rock to enable the flow of oil. Moving forward to 1947, Stanolind Oil experimented with “Hydrafrac” operations in Kansas that sound almost exactly like modern hydraulic fracturing operations, wherein the company pumped fluid and propping agents into a well to create fractures. Montgomery and Smith describe the ensuing commercial applications as follows:

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A patent was issued in 1949, with an exclusive license granted to the Halliburton Oil Well Cementing Company (Howco) to pump the new Hydrafrac process. Howco performed the first two commercial fracturing treatments—one, costing USD 900, in Stephens County, Oklahoma, and the other, costing USD 1,000, in Archer County, Texas—on March 17, 1949…. In the first year, 332 wells were treating, with an average production increase of 75%. Applications of the fracturing process grew rapidly and increased the supply of oil in the United States far beyond anything anticipated. Treatments reached more than 3,000 wells a month for stretches during the mid-1950s (4). Thus, March 17 is recognized as the birthday of hydraulic fracturing. In 1999, the U.S. Department of Energy released a report entitled Environmental Benefits of Advanced Oil and Gas Exploration and Production Technology, in which DOE identified both hydraulic fracturing and horizontal drilling as technologies that provide such benefits. This DOE report not only identified the environmental benefits of hydraulic fracturing, but also recognized the widespread use of the technology about a full decade before the onset of our current energy revolution: First introduced in 1947, hydraulic fracturing quickly became the most commonly used technique to stimulate oil and gas wells, ultimately enabling production of an additional eight billion barrels of North American oil reserves that would otherwise have been unrecovered. By 1988, fracturing had already been applied nearly a million times. Each year, approximately 25,000 gas and oil wells are hydraulically fractured (5). [Emphasis added.] In retrospect the only error in the paragraph above appears to be in the gross underestimate of U.S. oil supplies recoverable through hydraulic fracturing which, according to a 2013 estimate from EIA and Advanced Resources International, is 58 billion barrels. This vintage DOE report also provides this interesting assessment of hydraulic fracturing: It makes the development of some low-permeability, tight formations and unconventional resources economically feasible. When the flow of hydrocarbons is restricted by formation characteristics, injecting pressurized fluids and solid additives can stimulate wells to increase production. Fluids are pumped into the formation at pressures great enough to fracture the surrounding rock. A proppant flurry follows, biodegrading the sand proppant that holds the fractures open, allowing free passage of fluids to the wellhead. So successful has this technology been that the industry currently spends a billion dollars annually on hydraulic fracturing (5). The current shale boom has brought with it a major surge in investment related to hydraulic fracturing far greater the $8 billion cited by DOE in this 1999 report. In 48 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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its economic study on the impacts of unconventional resource development, IHS estimates investment levels at a $121 billion level in 2012 and projected to rise to $240 billion in 2025 (6). The difference in the application of hydraulic fracturing from 1999 to today is in the move from primarily vertical wells and conventional formations to the widespread use in horizontal wells and shale and tight sandstone formations. The dramatic turnaround in the energy landscape brought about by hydraulic fracturing led The Economist to characterize the U.S. as “The petrostate of America” a February 15, 2014 editorial, declaring: All of this is a credit to American ingenuity. Commodities have been a mixed blessing for other countries (see our leader on Argentina). But this oil boom is earned: it owes less to geological luck than enterprise, ready finance and dazzling technology. America’s energy firms have invested in new ways of pumping out hydrocarbons that everyone knew were there but could not extract economically. The new oilfields in Texas and North Dakota resemble high-tech factories. “Directional” drills guided by satellite technology bore miles down, turn, bore miles to the side and hit a target no bigger than a truck wheel. Thousands of gallons of water are then injected to open hairline cracks in the rock, and the oil and gas are sucked out (7). So successful is the development of unconventional resources that the drilling of a dry hole in these formations is a rarity. The “hunting and gathering” aspects of onshore conventional wildcatting have in many ways been replaced by “farming and harvesting” aspects of unconventional horizontal production. A frequently asked question is why this is an uniquely American success story. It is certainly not because the U.S. is the only country with potentially rich resources of unconventional oil and gas. The estimated world shale gas and shale oil resources as identified by EIA and Advanced Resources International (ARI) demonstrate that the U.S. is not alone in possessing substantial amounts of the resources (8). According to EIA, China, Argentina, and Algeria may be ahead of the U.S. in estimated shale gas resources and others appear to also possess huge quantities. (ARI’s estimate puts the U.S. in first place in technically recoverable shale gas resources.) Likewise, the U.S. is second in estimated shale oil resources with Russia in the lead and China, Argentina, Libya and Australia holding potentially large deposits. Shale oil and shale gas production is only occurring in four countries. According to EIA, the U.S., Canada, China and Argentina are the only countries producing shale oil or gas in commercial quantities, and the “United States is by far the dominant producer of both shale gas and tight oil (9).” The Economist partly answers this question in discussing American ingenuity as a key, stimulating factor in the energy boom. Other driving factors that have spurred the U.S. shale revolution include private mineral ownership; an established system of state permitting and regulation of oil and gas operations, with the proven flexibility to adapt and tailor its regulations and enforcement mechanisms; a comprehensive network of existing infrastructure, in the form of drilling rigs, materials and personnel on the production side and processing 49 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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plants, pipelines, marine transport, rail transport and terminals on the midstream side; a ready market with ample demand to utilize oil and gas for transportation, home heating and cooling, electricity generation, back-up energy for renewables, manufacturing, petrochemical and other uses; and a fundamental desire to become, if not energy independent, then energy secure in order to help enhance our overall national security. Over the long term, the U.S. and the world will continue to greatly rely on oil and natural gas to fuel their economies. The EIA expects large increases in energy efficiency, conservation and the use of renewables, but the EIA still projects oil and natural gas to constitute 60 percent of the U.S. energy portfolio and 55 percent of the global energy portfolio in 2040 (10). The shale energy renaissance is arguably in its infancy and current projections indicate that hydraulic fracturing will be a key asset in ensuring secure supplies of oil and gas for decades to come. This chapter will explore the economic benefits that are tightly linked to the use of hydraulic fracturing, as well as the industry standards that are in place to ensure that this energy is produced safely, responsibly and with confidence.

Economic Benefits – Increased U.S. Energy Production Because of hydraulic fracturing, the United States has transitioned from an era of perceived energy scarcity to an era of energy abundance. The pursuit of energy independence has been the touchstone of Presidential pursuits for decades. As Mr. Yergin explained in his New York Times piece, energy independence is no longer a laughing matter, and the shale energy revolution – led by the application of hydraulic fracturing – has positioned the U.S. for strength in oil and gas supplies. Using 2008 as a baseline, with the shale revolution getting underway at that time, we have witnessed the growth of U.S. marketed natural gas production from 21 trillion cubic feet per year to 27 trillion cubic feet per year in 2014, a 28.6 percent increase (11). In the same years, U.S. consumption increased from 23 Tcf per year to about 27 Tcf per year. In a dramatic turnaround, the U.S. has moved from being an importer of natural gas to becoming self-sufficient in natural gas (11). In 2008, the EIA was projecting that the U.S. was on track to become an importer of about 2.8 Tcf per of liquefied natural gas (LNG) per year, amounting to about $18 billion annually in LNG imports (12). However, LNG facilities that were once designed for imports are now going through the laborious government permitting process to transition to exports. The U.S. became the world’s largest producer of natural gas in the 2009 to 2010 timeframe, and EIA stated that “[i]ncreased use of horizontal drilling in conjunction with hydraulic fracturing spurred natural gas supply gains (13).” Looking ahead, EIA projects domestic natural gas production to continue to increase to meet growing U.S. demand for this clean-burning, affordable resource and potentially also for supplying our allies around the globe with secure shipments of natural gas. EIA projects production to rise to 38 Tcf per year in 2040 with most of this increased production coming from shale and tight formations that rely upon hydraulic fracturing; EIA predicts production from shale and tight formations will increase by 10 Tcf per year from 2012 to 2040 (14). 50 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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On the oil side, the story is much the same, with tight oil production driving the surge in overall U.S. crude oil production. In 2008, the U.S. averaged exactly 5 million barrels of crude oil production per day, and in December of 2014 U.S. production climbed to 9.2 million barrels per day, at a level not seen since May of 1974 (15). Production from tight oil formations has increased rapidly. Tight oil production averaged less than 1 million barrels per day in 2010 and was already accounting for more than 3 million barrels per day by the end of 2013 (14). EIA’s 2014 Annual Energy Outlook included three scenarios for projecting future U.S. crude oil production. The low resource case has production peaking at 9.1 million barrels per day, a level that has since been exceeded; the middle resource case has production peaking at 9.6 million barrels per day; and the high resource case has production peaking at more than 13 million barrels per day (14). In all three cases, production remains at levels above 6.5 million barrels per day through the year 2040, and in the high resource case crude oil production is projected to be at more than 13 million barrels per day in 2040 (14). EIA projects tight oil production alone to peak in a range between 4.3 and 8.5 million barrels a day (14). Of course, the price of oil and natural gas factors into the EIA projections, and future EIA reports will necessarily adjust as price and other factors fluctuate. Furthermore, the amount of estimated technically recoverable oil and gas resources for the U.S. has climbed significantly due to increased estimates of recoverable shale oil and gas resources. In 2008, U.S. technically recoverable oil resources as estimated by EIA stood at about 160 billion barrels and today the estimate stands at about 220 billion barrels (12, 14). On the natural gas side, EIA estimated U.S. natural gas resources at about 1,600 Tcf in 2008 and today the estimate is that we have about 2,400 Tcf (12, 14). The big jump is due to our continuously improving ability to recover shale oil and gas resource through the cost-effective use of hydraulic fracturing and horizontal drilling. EIA’s estimates now include 58 billion barrels of shale oil and 665 Tcf of natural gas resources. EIA’s estimates may actually be considered conservative, given that ARI estimates U.S. shale resources at 1,161 Tcf and ICF International estimates them at more than 1,900 Tcf (8). The rapid increases in production of oil and natural gas from shale and tight formations actually led the EIA to develop and publish a Drilling Productivity Report beginning in October 2013. The conclusion to be drawn from this monthly report is, not only is the U.S. rich in shale oil and gas resources, but U.S. companies continue to get better and better at developing oil and gas from these formations. The number one finding of the initial report states “[i]creases in drilling efficiency and new well productivity, rather than an increase in the number of active rigs, have been the main drivers of recent growth in domestic oil and natural gas production (16).” Drilling Productivity Reports from October 2013 through March 2015 have consistently demonstrated that the industry is continuously improving its ability to get more oil and gas from each well drilled. For example, a new well in the Bakken formation in November 2012 was producing just under 300 barrels of oil per day and a new Bakken well in March 2015 was estimated to be producing 577 barrels per day. The same trend is true for natural gas production. A new well in the Marcellus formation in November 2012 was producing about 4,500 million cubic feet of gas per day and 51 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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a new Marcellus well in March 2015 was estimated to be producing more than 8,000 million cubic feet of gas per day. This tremendous growth in productivity is owed to advancements in both drilling and hydraulic fracturing technology, as well as improved understanding of reservoir characteristics and performance. These compelling improvements in efficiency and productivity bode well for the future of oil and gas development in the U.S., and the world, because the industry is getting better and better at its work, getting more and more resource from each rig, each well, and each stimulation, and thereby advancing its overall cost-effectiveness by leaps and bounds. U.S. supplies have fundamentally shifted the global balance of energy power. When looking at the production of crude oil combined with production of natural gas liquids, the United States’ production has already surpassed that of both Saudi Arabia and Russia, according to the International Energy Agency and Bank of America (17). This is based upon U.S. production of crude oil and natural gas liquids (NGLs) surpassing 11 million barrels per day in the first quarter of 2014 and remaining above that level throughout 2014. (Crude and NGL production actually hit 12.5 million barrels per day in December 2014 according to EIA.) In his 2012 New York Times piece, Daniel Yergin elaborated on the significance of the rise of U.S. energy in global markets: According to the old script, United States oil production was too marginal to affect world oil prices. But the gap today between demand and available supply on the world market is narrow. The additional oil Saudi Arabia is putting into the market will help replace Iranian exports as they are increasingly squeezed out of the market by sanctions…. But if America’s increase of 1.6 million barrels per day since 2008 had not occurred, then the world oil market would be even tighter. We would be looking at much higher prices – and voters would be even angrier (1). The Economist cut quickly to the chase in its December 6, 2014 “Shiekhs vs. Shale” editorial: So the economics of oil have changed. The market will still be subject to political shocks: war in the Middle East or the overdue implosion of Vladimir Putin’s keptocracy would send the price soaring. But, absent such an event, the price of oil should be less vulnerable to shocks or manipulation. Even if the 3m extra b/d that the United States now pumps is a tiny fraction of the 90m the world consumes, America’s shale is a genuine rival to Saudi Arabia as the world’s marginal producer (18). In other words, U.S. shale oil and gas production now are now undeniably a critical factor in the global energy equation.

52 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Economic Benefits – Jobs, Money, and More Jobs A healthy U.S. energy production sector brings with it a strong U.S. economic stimulus in the form of capital investment, job creation, and affordable supplies of vital fuels for the economy. The oil and natural gas supply chain is long and strong, requiring steel, cement, equipment, machinery, valves, controls, trucks, tanks, boots, protective gear, information systems hardware and software, and, most importantly, people: people to make the steel and cement, protective gear and computer systems; people to use and apply the materials, equipment and technology systems; and people to develop the chain of infrastructure to process and deliver the oil and natural gas to the consumer. Oil and natural gas has been a stalwart in the economy since production began in the U.S., but particularly so in the past few years. A PriceWaterhouseCoopers 2013 report entitled Economic Impacts of the Oil and Natural Gas Industry in 2011 showed that America’s oil and natural gas industry – including both operation and capital investments – supported 9.8 million jobs in 2011, accounting for 5.6 percent of the total U.S. workforce. According to the report, These impacts result directly from the employment and production within the oil and gas industry, indirectly through the industry’s purchases of intermediate and capital goods from a variety of other US industries, and by the personal purchases of employees and business owners both within the oil and natural gas industry and out of the additional income in the supply chain to the industry and from dividends received from oil and natural gas companies (19). The report also concluded the “industry’s total impact on US GDP was $1.2 trillion, accounting for 8.0 percent of the national total in 2011 (20).” More specifically, the energy renaissance driven by hydraulic fracturing has been a driving force behind economic and job growth over the past several years. A report by IHS, America’s New Energy Future: The Unconventional Oil and Gas Revolution and the US Economy; Volume 3: A Manufacturing Renaissance – September 2013 reveals the clear benefits of the development of unconventional oil and gas resources, or those resources that rely upon hydraulic fracturing for extraction. This revolution has brought with it $121 billion in capital expenditures in 2012, projected to increase to $240 billion in 2025 and expected to total $2.75 trillion from 2012 through 2025. From a jobs standpoint, unconventional resource development supported 2.1 million jobs in 2012 and this is expected to increase to a level of 3.9 million jobs in 2025, with more than 500,000 of the jobs in 2025 in manufacturing. When considering GDP, unconventional development accounted for $284 billion in value added contributions in 2012, projected to rise to $533 billion in 2025. And the government derives tremendous benefits as well, receiving an additional $74 billion in revenues at the state and federal levels in 2012, expected to increase to a level of $138 billion in 2025. It is important to note that reports that project future economic impact take into account certain price assumptions. As economic realities set in, the actual economic impacts 53 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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may ultimately diverge from the initial projections. With price levels for crude oil actually lower than initially projected, the economic impacts likely would also be lower over the short term. In any event, the reports cited in this paper are illustrative of the economic impacts that have already occurred and the types of impacts that may occur as the shale revolution presses into the future. Businesses throughout the country in every state are helping to contribute to the success of the shale oil and gas boom, and putting Americans to work in many ways as part of it. The American Petroleum Institute conducted a survey in 2014 entitled Oil and Natural Gas Stimulate American Economic and Job Growth: Vendor Survey Findings Report. The survey provides a list of nearly 30,000 companies through the country, located in every state and almost every Congressional district that are contributing to and benefitting from the shale energy revolution. The actual number of such business is in reality much higher. For example, whereas the report includes the names of more 600 business located throughout the State of Ohio, the Ohio Department of Job and Family Services has reported that there are more than 13,000 shale-related business establishments in the state. The report makes it very clear that the businesses and workers in the unconventional oil and gas supply chain are both plentiful and diverse, including businesses small, medium and large, and companies such as small equipment suppliers, warehouses, large container makers, real estate companies, landscape restoration companies, uniform suppliers, port-o-john companies, and many, many more. These positive impacts of the energy revolution are not only being experience by oil and gas producing states, but also by states that are not recognized for energy production. Take New York as an example, which is a state that has imposed a moratorium on hydraulic fracturing but ironically is receiving great benefits from energy development that relies upon hydraulic fracturing. The API vendor survey provides a list of over 390 companies in the Empire State that get business from oil and gas development. Moreover, the IHS Manufacturing Renaissance report shows that unconventional oil and gas development supported 44,000 New York jobs in 2012 and this is expected to increase to 78,000 in 2025. Small businesses play a significant role in energy development. According to U.S. Census Bureau data, roughly 359,000 people are employed by small business within the upstream (exploration and production) oil and natural gas industry and upstream support industries, accounting for 45 percent of employment in those sectors. The small business contribution to upstream activities is broken down in Table 1 from the Census Bureau data (20):

54 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Table 1. Small Business Contribution to Upstream Oil and Natural Gas Activities NAICS Code

Industry Sector

Number of Small Businesses

Small Business Employment

211111

Crude petroleum and natural gas extraction

6,334

46,329

211112

Natural gas liquid extraction

92

1,507

213111

Drilling oil and gas well

1,921

32,177

213112

Support activities for oil and gas operations

7,057

44,855

23712

Oil and gas pipeline and related structures construction

1,559

36,535

23891

Site preparation contractors

34,210

184,405

333132

Oil and gas field machinery and equipment mfg.

512

13,587

54136

Geological surveying and mapping services

833

4,385

52,519

359,395

Total

Moreover, jobs in oil and natural gas can pay extremely well. The federal minimum wage pays $15,000 per year and the average job in the U.S. pays $49,700. In stark contrast, as seen in Table 2 below, jobs in oil and gas can pay more than twice the U.S. average (21):

Table 2. Average Annual Pay for Upstream and Related Oil and Natural Gas Sectors Industry Sector

Average annual pay

Oil and natural gas extraction

$154,317

Pipeline transportation

$116, 425

Drilling oil and gas wells

$94,115

Support activities for oil and gas

$81,696

Oil and gas pipeline construction

$72,667

55 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Last, but certainly not least, business and consumers are benefitting enormously from abundant supplies of affordable oil, natural gas, and natural gas liquids supplies. Fundamentals of market economics are quite evident in oil and gas markets, with growing U.S. supplies putting downward pressure on the price of oil and natural gas. The Henry Hub price of natural gas has remained at $6.00 per millions of British thermal units (mmBtu) or less since December 2008, with most of the month since then with an average price in the $2 to $4 range (11). The abundant supplies of natural gas in the U.S. and the ability of U.S. producers to efficiently produce these resources has led the EIA and other analysts to predict natural gas prices to remain relatively low for many years. The low price of natural gas led IHS to conclude, in part, in its Manufacturing Renaissance report, that the average consumer had $1,200 additional disposable income in 2012, expected to increase to $3,500 in 2025. Similarly, the price of crude oil has come down significantly. The spot price for West Texas Intermediate crude oil averaged $95 per barrel in January 2014 (15). By December 2014 it was down to $59 and in January 2015 it was at $47 (15). According to The Economist in its “Sheikhs vs. Shale” piece: “Cheaper oil should act like a shot of adrenaline to global growth…. A typical American motorist, who spent $3,000 in 2013 at the pumps, might be $800 a year better off – equivalent to a 2% pay rise (19).” The shale energy boom has also been a catalyst to resurgent manufacturing and petrochemical sectors, which rely on low cost energy to fuel operations and on natural gas and natural gas liquids as feedstock for production. For example, the American Chemistry Council (ACC) has identified 197 chemical industry investment projects valued at $125 billion that have been announced as of September 2014 (22). According to ACC, during peak investment year, these projects could support 275,000 jobs, $16 billion in payroll, and $46 billion in output. Those projects could also generate $18 billion in permanent local, state and federal government revenue by 2023. As indicated by the report, these investments and projects are made possible by lower natural gas prices and increased availability of ethane, an NGL and key chemical feedstock, which are a result of the shale energy revolution. Also, the IHS Manufacturing Renaissance report concludes that “the combined upstream, midstream and downstream unconventional oil and gas production process, and the chemical industry benefiting from it, will support more than 460,000 combined manufacturing jobs by 2020, rising to nearly 515,000 by 2025.”

National Security The positive geopolitical and national security implications of the re-emergence of the United States as an energy superpower are huge. Fundamentally, the more oil and natural gas that the U.S. produces here at home, the less the U.S. and the rest of the world need to buy from unfriendly regimes who often use energy as a political weapon. General Martin Dempsey, Chairman of the Joint Chiefs of Staff, had this to say about the opportunity presented by 56 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

U.S. energy independence and exports during a hearing of the Subcommittee on Defense Appropriations in the U.S. House of Representatives in March 2014:

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An energy independent [U.S.] and net exporter of energy as a nation has the potential to change the security environment around the world – notably in Europe and the Middle East. And so, as we look at our strategies for the future, I think we’ve got to pay more and particular attention to energy as an instrument of national power. And because it will very soon in the next few years potentially become one of our more prominent tools (23). Our allies in places like Central and Eastern Europe and Southeast Asia have a significant policy interest in seeing the U.S. produce and export more oil and natural gas. On the oil side, the U.S. is importing much less because of the increased domestic production. This means an improving trade imbalance, which can weigh heavily on the economy, and less oil purchased from foreign nations. On the natural gas side, the fact that the United States is not importing significant quantities of natural gas means that there are substantially more quantities on the global market, giving nations around the world greater supplies and greater diversity of supply to choose from. Unfriendly regimes rely upon their own oil and natural gas to both fund their governments and militaries and to exercise power over neighboring countries. This is particularly true on the natural gas side with much of Eastern Europe almost fully dependent upon Russian gas for supplying its economies, and the rest of Europe tied to that market as well. According to a January 10, 2013 editorial in the Wall Street Journal, “in Europe, American LNG exports will be a welcome source of diversification to cut energy dependence on Russia (24).” On the oil side, both the increased supplies on the global market and the decrease in the price of crude oil resulting from the U.S. energy boom weigh heavily on threatening oil producing regimes. According to The Economist editorial “Many winners, a few bad losers” published on October 25, 2014, “For those governments that have used the windfall revenues from higher prices to run aggressive foreign policies…things could get uncomfortable. The most vulnerable are Venezuela, Iran and Russia (25).” According to The Economist, Iran relies upon oil prices of $140 per barrel, Venezuela relies upon oil prices of $120 per barrel, and Russia upon oil at high prices to fund their government spending budgets. The U.S. shale revolution has helped to drive prices well below those levels, putting the future economic viability of those regimes at greater risk. The U.S. energy renaissance has certainly put the country in a much better place from a geopolitical standpoint than it could imagined even ten years ago. Increased U.S. production alone is having a significant impact on the world energy power dynamic. By opening up its borders to the free trade of oil and natural gas, the U.S. could have an even greater impact and we would be responding directly and positively to the pleas of our allies to share our resources. Exports of these commodities will not only increase our national security interests as described by General Dempsey, but will also increase production of oil and natural gas in the United States spurring additional spending and job growth throughout the country. 57 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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However, applications to export LNG linger in government bureaucracy and crude oil exports are subject to a 70s era ban that has long-outlived any purpose it may have served. It is in the best interests of the President and Congress to move past partisan gridlock over these issues and make the necessary decisions to expedite exports of both oil and natural gas. Both branches of Congress have the ability to make the necessary changes in both oil and natural gas export policy, and the President could do it today with the tools at his disposal. In discussing Liquified Natural Gas (LNG) exports, an op-ed in the Wall Street Journal by Robert Johnston and Leslie Palti-Guzman summed it as follows: “through its power to permit exports of U.S. gas…, the White House will effectively say yea or nay to the emergence of the U.S. as a global gas superpower. The world is waiting for an answer (25).”

A Balanced Approach to Harnessing the Benefits through Development and Implementation of Industry Standards The benefits of producing oil and natural gas from shale and tight formations through the use of hydraulic fracturing are obviously enormous from the many perspectives identified above. At the same time, the industry takes very seriously its commitment to produce oil and gas in a safe and environmentally responsible manner. This is evident in the industry’s continued development of standards and best practices designed to ensure safe and responsible development of the nation’s resources. Industry standards create the framework for safe, environmentally sound operations, and they are widely disseminated and shared within the industry and with regulators. Using industry standards helps to create a consistent basis for safe, environmentally sound operations. Industry relies on standards and best practices for safe operations and continuous improvement in the operating environment. Government regulators rely upon industry standards and best practices as a means to learn from and engage with the industry, and also for the design of a credible and effective regulatory and permitting regime for oversight of industry operations. The development and implementation of standards and best practices at its core ensures that we are harnessing the varied, positive and consequential benefits, and real world experience through a balanced approach that promotes safe and environmentally protective operations. The American Petroleum Institute (API) offers a full suite of robust industry standards and best practices for the safe development of shale energy resources. The API standards program, which was established in 1924, promulgates voluntary consensus standards that promote the use of safe, interchangeable equipment and operations through proven, sound engineering practices. The standards are developed collaboratively by industry experts and others from government, academia and other interested stakeholders, including professional societies. API’s more than 600 standards cover every aspect of the oil and natural gas business. They are widely used by companies in the United States and around the world and are frequently referenced in federal, state and international regulations. 58 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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API’s standards program is accredited by the American National Standards Institute (ANSI), which signifies that the procedures API uses to create standards meet all of ANSI’s essential requirements for openness, balance, consensus and due process. While hydraulic fracturing is a subset of the technical operations involved in the development of shale energy resources (hydraulic fracturing operations normally last for under seven days for a well that can be in production for 20 years or more), API has published well over 100 standards documents that relate and contribute to the safe, environmentally sound development of shale energy resources (26). API standards documents include the following different categories of documents: specifications, which are generally intended to create consistency around the design and manufacture of specific categories of materials and equipment, and “are written in such a way as to facilitate communications between purchasers, manufacturers, and/or service suppliers”; recommended practices, which” communicate recognized industry practices,” including how to generally conduct a particular operation; standards, which combine “elements of both specifications and recommended practices”; and bulletins and technical reports, which are generally guidance-type documents and “convey technical information on a specific subject or topic (27).” Examples of documents that fit into each of these categories include the following: • • • • •

API Specification 7K, Drilling Equipment API Recommended Practice 51R, Environmental Protection for Operations API Standard 65 Part 2, Isolating Potential Flow Zones API/ANSI Bulletin 100-3, Community Engagement Guidelines API Technical Report 10TR3, Cement Thickening Time Tests

It is through a full suite of API standards and best practices covering the various aspects of oil and gas development, including shale operations, that the industry is able to form a strong baseline for U.S. and global operations to conduct safe and environmentally responsible development. The portfolio of API standards and best practices applicable to shale oil and gas development is comprehensive, systematic and robust, but for purposes of this chapter we will focus on standards and best practices related to aspects of shale development and operations that have been the subject of active dialogue at the local, state and federal levels: community engagement, well integrity, water use and management, and environmental management. API standards and best practices related to each of these areas are designed to effectively address the relevant concerns by ensuring both a balanced dialogue with affected communities and by implementing operational practices to protect the environment.

59 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Community Engagement

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API’s Community Engagement Guidelines, API Bulletin 100-3, was published in July 2014 and constitutes a first of a kind document when it comes to providing guidelines for engaging with and respecting the local communities located where operations are intended to occur. Oil and gas development can be a new activity for a local community, and operators have been developing constructive best practices and tools to create close alignment with the priorities of local communities in and around locations of oil and gas development. API’s Community Engagement Guidelines brings together the collective thinking of the industry to establish a document with the following purpose: The Community Engagement Guidelines are recommendations designed to promote the safe and responsible development of the nation’s oil and natural gas resources by engaging and respecting the communities where these operations occur. The oil and gas industry can bring prosperity, economic development and enhancements to an area and assist in securing our national energy interests. In order to promote oil and gas development that results in a positive experience for communities, recommended development activities should be aligned with community concerns and priorities grounded in responsible practices and lessons learned from former experiences. The industry’s commitment to being a good neighbor throughout the full project life cycle requires ongoing dialogue with local communities and other key stakeholders. Stakeholders, for use of the Community Engagement Guidelines, are defined as: Any person, group or entity that has interest or concern in an organization and its activities is considered a stakeholder. Stakeholders can affect or be affected by the organization’s actions, objectives and policies (28). The document establishes a baseline of engagement for the industry and local communities by tying the five phases of an oil and gas project’s life cycle to the overarching principles of integrity, safety and environmental responsibility, and communicating effectively. The five phases of oil and gas projects include entry; exploration; development; operations/production; and exit. The phases are then broken down separately within the document in order to identify engagement considerations for operators and to provide insight into what can be expected by the local stakeholders. With regard to the principle of integrity, companies should “strive to build positive and constructive relationships within the community and accumulate long-term sustainable relationships (29).” With regard to the principle of safety and environmental responsibility, the “goal should be to operate daily in a manner that protects the safety, environment and health of communities, employees and contractors during the complete lifecycle of the project (30).” With regard to the principle of communicating effectively, companies are encouraged to “[p]romote education, awareness, and learning during the five phases of the project life cycle and work to bridge any knowledge gaps by providing tailored information that is targeted to the community (30).” 60 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Community engagement is both part of the planning process by identifying ways to mitigate potential impacts to local communities and part of the operations process by continuing to engage with local communities throughout the complete life cycle of the project to achieve the key principles discussed above. Moreover, the document is an effective tool that can be used by local communities to help achieve those objectives. As the document itself provides, the “oil and gas companies encourage communities to use these guidelines in a manner that invites conversation, facilitates learning and enhances cooperation, working collectively to mitigate potential impacts and driving for long-term sustainability.”

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Well Integrity API has published two documents that are directly designed to help ensure well integrity and the protection of groundwater resources: API Guidance Document HF1, Hydraulic Fracturing Operations – Well Construction and Integrity Guidelines (October 2009), and API Standard 65−Part 2, Isolating Potential Flow Zones During Well Construction (December 2012). According to HF1, well integrity is a key design principle and feature for all oil and natural gas wells, and maintaining integrity is essential for two reasons (30): 1.

2.

To isolate the internal conduit of the well from the surface and subsurface environment. This is critical in protecting the environment, including the groundwater, and in enabling well drilling and production. To isolate and contain the well’s produced fluid to a production conduit within the well.

HF1 is designed to provide guidance and highlight the recommended practices for hydraulically fractured wells. HF1 outlines the various considerations for an operator to take into account when designing and constructing a well so that groundwater and the environment are protected. The layers of protection inherent in both the well design and the geology of the rock are described as follows: Groundwater is protected from the contents of the well during drilling, hydraulic fracturing, and production operations by a combination of steel casing and cement sheaths, and other mechanical isolation devices installed as a part of the well construction process. It is important to understand that the impermeable rock formations that lie between the hydrocarbon producing formations and the groundwater have isolated the groundwater over millions of years (31). HF1 provides detailed guidance on drilling the hole, logging the hole, running casing (steel pipe), cementing the casing, logging the casing, perforating the casing, hydraulically fracturing or stimulating the well, and monitoring well performance. In addition to HF1, API has published Standard 65−Part 2, which provides practices for isolating potential flow zones by cementing, which is an “integral element in maintaining well integrity (32).” Standard 65−Part 2 is a 61 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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highly technical document and includes two primary objectives: “help prevent and/or control flows just prior to, during, and after primary cementing operations to install or ‘set’ casing and liner pipe strings in wells,” and “help prevent sustained casing pressure (33).” These objectives are important in the design and construction of any oil or natural gas well. In fact, Standard 65−Part 2 has been adopted by reference into regulation by the federal government’s Bureau of Safety and Environment Enforcement for offshore operations. The U.S. oil and gas industry has demonstrated great success ensuring that the objectives of the above well integrity standards are achieved and in preventing groundwater contamination. Tens of thousands of oil and natural gas wells are drilled each and every year, with a great portion of those wells being hydraulically fractured. The evidence strongly demonstrates that hydraulic fracturing has been effectively applied over the past several decades without adverse impact to groundwater supplies. In fact, an estimated 35,000 wells per year are hydraulically fractured and more than 1 million wells are estimated to have been hydraulically fractured since the first well in the late 1940s (33). Former U.S. Environmental Protection Agency (EPA) Administrator Lisa Jackson testified before Congress in May 2011 and stated there is no “proven case where the fracking process itself has affected water (34).” These sentiments have been echoed by various government officials and were reiterated more recently by EPA Administrator Gina McCarthy during her confirmation hearing in April 2013: “I am not aware of any definitive determinations that would contradict those statements [by Lisa Jackson, referenced above] (35).” Most recently, in its Draft Assessment Report on the Potential Impacts to Drinking Water Resources from Hydraulic Fracturing Activities released on June 4, 2015, EPA acknowledged that “hydraulic fracturing activities have not led to widespread, systemic impacts to drinking water resources.” The draft Assessment Report is the most complete compilation of scientific data to date (including over 950 sources of information, published papers, numerous technical reports, information from stakeholders and peer-reviewed EPA scientific reports) to assess the potential for hydraulic fracturing for oil and gas to impact the quality or quantity of drinking water resources. Nevertheless, the industry takes its commitment to groundwater protection very seriously. This is evident in the industry’s development and application of standards and best practices to maintain well integrity, and in the industry’s success in producing shale energy and gas from thousands upon thousands of wells without incident.

Water Use and Management API Guidance Document HF2, Water Management Associated with Hydraulic Fracturing (June 2010) was developed by the industry to “identify and describe many of the current industry best practices used to minimize environmental impacts associated with the acquisition, use, management, treatment, and disposal of water and other fluids associated with the process of hydraulic fracturing (36).” HF2 outlines the planning considerations for the acquisition, use and 62 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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management of water in hydraulic fracturing operations. These considerations are designed to address source water acquisition, transport, storage, use, reuse and recycle, and treatment and disposal. The document also includes a checklist of eleven key considerations for minimizing the environmental and societal impacts associated with those various water-related activities. For example, the first objective states that “[o]perators should engage in proactive communication with local water planning agencies to ensure oil and gas operations do not constrain the resource requirements of local communities and to ensure compliance with all regulatory requirements (37).” HF2 recognizes the primary role of local and state governments in water use and management decision making, and suggests opportunities for operators to seek to reduce future demands on available water resources.

Surface Environmental Management API has published two documents that help guide the industry to better overall environmental performance during oil and gas development operations: API Guidance Document HF3, Practices for Mitigating Surface Impacts Associated with Hydraulic Fracturing (January 2011) and API Recommended Practice 51R, Environmental Protection for Onshore Oil and Gas Production Operations and Leases (July 2009) (RP 51R). HF3 is designed to “identify and describe practices currently used in the oil and natural gas industry to minimize surface environmental impacts—potential impacts on surface water, soils, wildlife, other surface ecosystems and nearby communities—associated with hydraulic fracturing operations (36).” The various specific API standards described in this chapter are obviously interrelated and should be used together to create a synthesized approach in applying best practices. HF3 actually includes a section on water management, but is distinct from HF2 in that HF3 specifically discusses on-site fluid handling, surface impoundments and storage tanks, spill prevention and control, and storm water management and control. HF3 provides best practice considerations for maintaining equipment and facilities, minimizing surface disturbances, protecting air quality, preserving visual resources, and mitigating noise impacts. HF3 also discusses the importance of transparency regarding the disclosure of the chemical ingredients used in hydraulic fracturing operations. Disclosure has been made possible by the development and widespread use of the FracFocus chemical disclosure registry, which provides for well-by-well disclosure of the specific components used in fracturing operations. As of June 4, 2015, more than 99,000 wells have been registered on the site. Most oil and natural gas producing states have disclosure requirements as part of their regulatory programs, and the great majority require disclosure through FracFocus. The public can readily review this information at www.fracfocus.org. RP 51R adds important elements for planning and operations by addressing considerations for lease roads, waste management, pit location and construction, handling of water discharges, waste disposal, lease gathering and systems lines, and production and water handling facilities. RP 51R includes an important resource at Annex A, which is the document’s “Good Neighbor Guidelines.” 63 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

The Good Neighbor Guidelines have the three objectives of protecting the public safety, protecting the environment, and respecting the property rights of others. In order to effectively advance those objectives, the guidelines include this checklist of good neighbor practices: •

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• • • •

Listen to the land owner or surface user concerns and respond appropriately; Communicate with land owners and surface users; Respect the property and rights of others; Promote the safety of the general public; and Protect the environment.

The specific API standards documents described above are only six examples of more than 100 API standards that promote safety and environmental performance in onshore oil and gas exploration and production operations, yet they serve to comprehensively guide operators in identifying aspects of operations that have the potential to impact local communities and the environment and provide a roadmap for determining best practices to mitigate and prevent such potential impacts. Fundamentally, oil and gas companies are committed to safe and environmentally responsible oil and gas development. At its core, safety is good business, and good business is safety. The commitment of the industry to safe, environmentally sound operations is abundantly evident through its voluntary development and utilization of standards and best practices that form a comprehensive, systematic and robust framework for safe and environmentally responsible operations. This commitment and framework serve to credibly demonstrate the balanced approach in place in the U.S., which harnesses the tremendous positive benefits of shale energy development and promotes prudent and responsible development.

Effective System of State-Based Regulation Serves To Ensure a Balanced Approach The leadership of the industry in advancing a strong system of standards and best practices is complemented by an effective regime of state-based permitting, regulation and enforcement. State level governments and regulators have been effectively overseeing oil and natural gas operations for decades, and have ensured that requirements and standards are in place for safe operations, protection of public health and interests, and protection of the environment. Oil and gas producing states have regulatory structures in place for the protection of surface and groundwater, the disclosure of the components of hydraulic fracturing fluids used to stimulate production of oil and gas, and the use and management of water resources. According to its website, the “Interstate Oil and Gas Compact Commission [IOGCC] is a multi-state government agency that promotes the conservation and efficient recovery of domestic oil and natural gas resources while protecting health, 64 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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safety and the environment (38).” The membership of the IOGCC is comprised of the Governors of the oil and natural gas producing states in the U.S. According to the IOGCC, “hydraulic fracturing is regulated by the states. IOGCC member states each have comprehensive laws and regulations to provide for safe operations and to protect drinking water sources, and have trained personnel to effectively regulate oil and gas exploration and production (39).” The IOGCC expands upon this by stating, “[t]he Commission’s member states have a well-established history in successful regulation resulting in sound environmental practices. Issues vary from state to state, and experienced regulators across the nation have shown great leadership in protecting our environment. Many times, federal regulations offer a “one size fits all” approach, which does not effectively regulate the oil and natural gas industry (40).” And recently, IOGCC and the Groundwater Protection Council (GWPC) worked together to create the States Oil and Gas Regulatory Exchange (SOGRE) to help facilitate the flow of information between oil and gas regulators. One of the first projects of SOGRE was the 2014 publication of a reported entitled State Oil and Gas Regulations Designed to Protect Water Resources. The report includes the following statement in the preface to the document: State regulators place great emphasis on protecting water resources from adverse impacts that can occur during oil and natural gas exploration and production (E&P) activities. The GWPC and Interstate Oil and Gas Compact Commission (IOGCC) believe that regulation of oil and gas field activities is managed best at the state level where regional and local conditions and best applied practices are understood, and where regulations can be tailored to fit those conditions. While there are aspects of oil and gas regulation that occur at the local and federal government level, in the vast majority of instances the greatest experience, knowledge, and information necessary to regulate effectively resides with state regulatory agencies (41). Then, after reviewing the regulatory programs of 27 oil and gas producing states, the report includes the following as the ultimate conclusion: Overall, state oil and natural gas regulatory agencies have been diligent in addressing the technological, legal and practical changes that have occurred in oil and gas E&P over the past four years. By employing highly trained, experienced staff and implementing rules designed to protect water resources, agencies have maintained a standard of regulatory management that assures water availability and sustainability (42). Given the success of the oil and gas producing states in implementing comprehensive and effective regulatory systems for environmental protection, and the clear interest of those states, as expressed above, in continuing to maintain primary responsibility for environmental oversight, it is clear that the state-based 65 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

approach serves as an effective mechanism for ensuring a balanced approached to shale energy development.

Environmental Benefits of Hydraulic Fracturing

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In 1999, the U.S. Department of Energy Office of Fossil Energy published a report entitled the Environmental Benefits of Advanced Oil and Gas Exploration and Production Technology. The report included both horizontal drilling and hydraulic fracturing as advanced technologies that provide environmental benefits. With regard to hydraulic fracturing, the report identified the following environmental benefits: • • •

Optimized recovery of valuable oil and gas resources Protection of groundwater resources Fewer wells drilled, resulting in less waste requiring disposal

The report also included the following economic benefits: Increased well productivity and ultimate recovery Significant additions to recoverable reserves Greatly facilitated production from marginal and mature fields As described throughout this chapter, the economic and environmental benefits of shale oil and gas have played out through the current energy renaissance, some 16 years after the publication of this government report. And the environmental benefits are much greater than described in that 1999 DOE report. The shale energy revolution has unleashed affordable, abundant supplies of clean-burning natural gas, which have helped contribute to lower greenhouse gas (GHG) emissions. According to EIA, U.S. carbon dioxide (CO2) emissions resulting from energy use during the first quarter of 2012 were the lowest in two decades (43). The U.S. State Department concluded that “a major contributor to the decline in U.S. GHG emissions has been the displacement of coal with natural gas that is extracted from shale rock formations through hydraulic fracturing and horizontal drilling (44).” In addition to the GHG benefits, electricity generated from natural gas produces very low emissions of carbon monoxide, nitrogen oxides, particulate matter, volatile organic compounds, and sulfur dioxide, and no emissions of mercury. The shale energy boom has truly unlocked a resource that provides the triple benefit of driving significant economic growth, enhancing global energy security, and producing clean energy.

The U.S. as an Energy Superpower: Harnessing the Benefits for Generations to Come Looking back on the past few years, it is clear that the shale revolution has provided a much needed bright spot for the U.S. economy during the height of the recent recession. According to EIA, from “the start of 2007 through the end 66 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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of 2012, total U.S. private sector employment increased by more than one million jobs, about 1%. Over the same period, the oil and natural gas industry increased employment by more than 162,000 jobs, a 40% increase (45).” Numbers like these led the Washington Times to run a June 3, 2014 op-ed by Richard Rahn entitled “How Fracking has Saved Obama.” Mr. Rahn maintains that “[w]ithout fracking of oil and gas deposits, there would have been no economic growth in the U.S. over the past five years…. Without those brilliant entrepreneurs and engineers in the private sector who developed the new techniques to unlock massive amounts of oil and gas at reasonable cost, it is unlikely that President Obama would have been re-elected (46).” Of course, this is a question to which we will never know the answer, because hydraulic fracturing did advance in America and has generated tremendous economic growth, and President Obama was re-elected. Looking ahead, we know from EIA projections that America and the world will continue to rely on oil and natural gas to fuel their economies for decades to come. According to EIA, in the year 2040, the U.S. is projected to rely upon oil and natural gas for about 60 percent of its fuel needs and the world is projected to rely on oil and natural gas for nearly 55 percent of its needs (10). EIA data shows that global oil demand alone is expected to rise by about 30 percent over the same time period, from about 90 million barrels per day in 2013 to about 117 million barrels per day in 2040 (47). Given the recent success of shale energy development in the U.S. in unlocking massive amounts of oil and natural gas, the question becomes whether shale development will see similar success on a global level. This same query led The Hill to run an op-ed by Dr. Robert Shum on March 18, 2014 entitled “Can fracking save the world?” Dr. Shum identifies various important global challenges that hydraulic fracturing can help address, including rising energy demand, concerns about climate change, and global geopolitical security. In re-emerging as a global energy superpower, the U.S. has already gone a long way toward addressing these important issues in a very positive way, for both American and our global allies. Perhaps, while not necessarily “saving the world,” shale energy development will continue in its trajectory as the logical response to the global call for affordable energy, economic stimulus, energy security and geopolitical leverage. If so, then we will all have hydraulic fracturing to thank for that.

References 1. 2. 3.

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Yergin, D. America’s New Energy Reality. The New York Times, June 9, 2012. Gold, R.; Gilbert, D. U.S. Rises to No. 1 Energy Producer. Wall Street Journal, October 3, 2013. API Guidance Document HF2, Water Management Associated with Hydraulic Fracturing; Amerian Petroleum Institure: Washington, DC, June, 2010; p 7 (for reproduction of DOE graphic). Montgomery, C. T.; Smith, M. B. Hydraulic Fracturing: History of an Enduring Technology. J. Pet. Technol. 2010, 27. 67 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Environmental Benefits of Advanced Oil and Gas Exploration and Production Technology; U.S. Department of Energy, Office of Fossil Energy, Washington, DC, 1999; p 95. America’s New Energy Future: The Unconventional Oil and Gas Revolution and the U.S. Economy; Volume 3: A Manufacturing Renaissance; IHS: Edgewood, CO, September 2013. The Petrostate of America, Editorial, The Economist, February 15, 2014; p 10. EIA/ARI World Shale Gas and Shale Oil Resource Assessment; Technical Report for the Energy Information Administration, U.S. Department of Energy, Washington, DC; prepared by Advanced Resources International, Inc, Arlington, VA, June 2013. Shale Gas and Tight Oil Are Commercially Produced in Just Four Countries; Today in Energy; Energy Information Administration: Washington, DC, February 13, 2015. http://www.eia.gov/todayinenergy/detail.cfm?id=19991 (accessed August 24, 2015). 2014 Annual Energy Outlook (http://www.eia.gov/forecasts/archive/aeo14/, accessed August 24, 2015) and International Energy Outlook 2013 (http:/ /www.eia.gov/forecasts/archive/ieo13/, accessed August 24, 2015), Energy Information Administration. Natural Gas, Energy Information Administration. http://www.eia.gov/ naturalgas/data.cfm#production (accessed August 24, 2015). Energy Information Administration, 2008 Annual Energy Outlook. http:// www.eia.gov/oiaf/archive/aeo08/index.html (accessed August 24, 2015). The U.S. Surpassed Russia as World’s Leading Producer of Dry Natural Gas in 2009 and 2010; Today in Energy; Energy Information Administration, Washington, DC, March 13, 2012. http://www.eia.gov/todayinenergy/ detail.cfm?id=5370 (accessed August 24, 2015). 2014 Annual Energy Outlook, Energy Information Administration. http:// www.eia.gov/forecasts/archive/aeo14/ (accessed August 24, 2015). Petroleum and Other Liquids, Energy Information Administration.http:// www.eia.gov/petroleum/data.cfm (accessed August 24, 2015). Highlights of New Drilling Productivity Report; Today in Energy; Energy Information Administration: Washington, DC, October 22, 2013. http://www.eia.gov/todayinenergy/detail.cfm?id=13471 (accessed August 24, 2015). Smith, G. U.S. Seen as Biggest Oil Producer after Overtaking Saudi, Bloomberg, July 4, 2014. Sheikhs v. Shale, Editorial, The Economist, December 6, 2014; p 17. Economic Impacts of the Oil and Natural Gas Industry in 2011; PriceWaterhouseCoopers: Washington, DC, July 2013. http://www.api.org/ ~/media/Files/Policy/Jobs/Economic_impacts_Ong_2011.pdf (accessed August 24, 2015). Statistics of U.S. Businesses, 2010 Annual Employment Data and 2007 Receipts Data; U.S. Census Bureau. http://www.census.gov/econ/susb/ (accessed August 24, 2015). 68 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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21. U.S. Quarterly Census of Employment and Wages, 2013, U.S. Department of Labor, Bureau of Labor Statistics, Washington, DC, at http://www.bls.gov/ cew/ (accessed Aug 24, 2015). 22. Shale Gas Competitiveness and New US Chemical Industry Investment: An Analysis Based on Announced Projects, American Chemistry Council, Washington, DC, May 2013, at http://chemistrytoenergy.com/sites/ chemistrytoenergy.com/files/shale-gas-full-study.pdf (accessed Aug 24, 2015). 23. A Gas Export Strategy, Editorial, Wall Street Journal, March 19, 2014. 24. Johnston, R.; Palti-Guzman, L. The Foreign Policy Uses of an Energy Bounty. Wall Street Journal, January 10, 2013. 25. Many winners, a few bad losers, Editorial, The Economist, October 25, 2014; p 16. 26. Hydraulic Fracturing Best Practices Overview, American Petroleum Institute. http://www.api.org/policy-and-issues/policy-items/hf/hydraulicfracturing-best-practices (accessed August 24, 2015). 27. Procedures for Standards Development; American Petroleum Institute: Washington, DC, September 2011. 28. Community Engagement Guidelines, ANSI/API Bulletin 100-3; American Petroleum Institute: Washington, DC, July 2014; p vi. 29. Community Engagement Guidelines, ANSI/API Bulletin 100-3; American Petroleum Institute: Washington, DC, July 2014; p 2. 30. Hydraulic Fracturing Operations – Well Construction and Integrity Guidelines, API Guidance Document HF1; American Petroleum Institute: Washington, DC, October 2009; p 1. 31. Hydraulic Fracturing Operations – Well Construction and Integrity Guidelines, API Guidance Document HF1; American Petroleum Institute: Washington, DC, October 2009; p 2. 32. Isolating Potential Flow Zones During Well Construction, API Standard 65 − Part 2; American Petroleum Institute: Washington, DC, December 2012; p 1. 33. Practices for Mitigating Surface Impacts Associated with Hydraulic Fracturing, API Guidance Document HF3; American Petroleum Institute: Washington, DC, January 2011; p 4. 34. Pain at the Pump: Policies That Suppress Domestic Production of Oil and Gas: Hearing before the H. Comm. on Oversight and Government Reform, 112th Congress, May 24, 2011. 35. Questions for the Record, Gina McCarthy Confirmation Hearing: Hearing before the S. Comm. on Env. and Pub. Works, 113th Congress, April 29, 2013. 36. Water Management Associated with Hydraulic Fracturing, API Guidance Document HF2; Washington, DC, June 2010; p 1. 37. Water Management Associated with Hydraulic Fracturing, API Guidance Document HF2, Washington, DC, June 2101; p. vi. 38. About Us, Interstate Oil and Gas Compact Commission. http:// iogcc.publishpath.com/vision-mission-values (accessed August 24, 2015). 69 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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39. Hydraulic Fracturing, Interstate Oil and Gas Compact Commission. http:// iogcc.publishpath.com/hydraulic-fracturing (accessed August 24, 2015). 40. States’ Rights, Interstate Oil and Gas Compact Commission. http:// iogcc.publishpath.com/states-rights (accessed August 24, 2015). 41. State Oil and Gas Regulations Designed to Protect Water Resources; Groundwater Protection Council, Interstate Oil and Gas Compact Commission, and State Oil and Gas Regulatory Exchange, Oklahoma City, OK, 2014; p 1. 42. State Oil and Gas Regulations Designed To Protect Water Resources; Groundwater Protection Council, Interstate Oil and Gas Compact Commission, and State Oil and Gas Regulatory Exchange, Oklahoma City, OK, 2014; p 6. 43. U.S. Energy-Related CO2 Emissions in Early 2012 Lowest Since 1992; Today in Energy, Energy Information Administration: Washington, DC, August 2012. http://www.eia.gov/todayinenergy/detail.cfm?id=7350 (accessed August 24, 2015). 44. U.S. Climate Action Report 2014; U.S. Department of State: Washington, DC, 2014; p 51. http://www.state.gov/documents/organization/219038.pdf (accessed August 24, 2015) 45. Oil and Gas Industry Employment Growing Much Faster than Total Private Sector Employment; Today in Energy, Energy Information Administration: Washington, DC, August 8, 2013. http://www.eia.gov/todayinenergy/ detail.cfm?id=12451 (accessed August 24, 2015). 46. Rahn, R. How Fracking Has Saved Obama, Washington Times, June 3, 2014. http://www.washingtontimes.com/news/2014/jun/2/rahn-how-fracking-hassaved-obama/ (accessed August 24, 2015). 47. 2013 International Energy Outlook, Energy Information Administration, July 2013. http://www.eia.gov/forecasts/archive/ieo13/ (accessed August 24, 2015).

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Chapter 3

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Using Discovery Science To Increase Efficiency of Hydraulic Fracturing While Reducing Water Usage H. S. Viswanathan,* J. D. Hyman, S. Karra, J. W. Carey, M. L. Porter, E. Rougier, R. P. Currier, Q. Kang, ́ ez, N. Makedonska, L. Zhou, J. Jimenéź -Martín L. Chen, and R. S. Middleton Los Alamos National Laboratory, P.O. Box 1663, Los Alamos, New Mexico 87545, United States *E-mail: [email protected]

Shale gas is an unconventional fossil energy resource that is already having a profound impact on United States (US) energy independence and is projected to last for at least 100 years. Production of methane and other hydrocarbons from low permeability shale involves hydraulically fracturing rock, establishing fracture connectivity, and multiphase fluid-flow and reaction processes, all of which are poorly understood. The result is highly inefficient extraction that also raises many environmental concerns. A science-based capability is required to quantify the governing mesoscale fluid-solid interactions, including microstructural control of fracture patterns, and the interaction of engineered fluids with hydrocarbon flow that is required for increasing efficiency and decreasing the potential of environmental impacts. These interactions depend on several complex coupled thermo-hydro-mechanical-chemical (THMC) processes over scales ranging from nanometers to kilometers. Determining the key mechanisms in subsurface THMC systems has been impeded due to the lack of sophisticated experimental methods to measure fracture aperture and connectivity, permeability, and chemical exchange capacities at the high temperature, pressure, and stresses present in the subsurface. In

© 2015 American Chemical Society In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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this chapter, we describe innovative experimental techniques and simulation methodologies to address these issues. We use high-pressure microfluidic and triaxial core flood experiments on shale to better constrain fracture-permeability relations and the extraction of hydrocarbon. These data are integrated with simulations including lattice Boltzmann modeling of pore-scale processes, finite-element/discrete element approach for fracture initiation and propagation in the near-well environment, discrete fracture network modeling at the reservoir-scale for modeling transport through large-scale fractures, and system-scale models to assess the economics of alternative fracturing fluids. The ultimate goal is to make the critical measurements needed to develop models that can be used to determine the reservoir operating conditions necessary to gain a degree of control over fracture generation, fluid flow, and interfacial processes over a range of in situ subsurface conditions.

Introduction Shale gas is an unconventional fossil energy resource that is already having a profound impact on the US energy sector, with reserves projected to last for nearly 100 years (1). The increased availability of shale gas (i.e., methane), which produces 50% less carbon dioxide (CO2) than coal when used as a fuel, is primarily responsible for US CO2 emissions dropping in 2011 to their lowest levels in 20 years (2). However, these unconventional resources formations, e.g., tight sandstones; shales; and coal beds, have very low permeability (microdarcy-nanodarcy), and the extraction of methane and other hydrocarbons from these low permeability formations involves the hydraulic fracturing of the shale rock to increase fracture connectivity and liberate the in place methane. The process of hydraulic fracturing is poorly understood in part due to the wide range of length scales involved. The result of this ignorance is inefficient extraction that raises many environmental concerns (3, 4). The sustainability of this unconventional energy source depends on improving our understanding of why and how hydraulic fracturing works. Using this knowledge, new technologies for optimizing and enhancing the gas production while simulations decreasing environmental risks must be developed to reach this goal. At Los Alamos National Laboratory (LANL), we have been developing experiments and models that can characterize many of the coupled phenomena involved in hydraulic fracturing, e.g., fracture generation; multiphase fluid flow; and chemical processes, under in situ conditions at the reservoir, core, pore-structure and individual pore scales (Figure 1). Our goal is to reveal the fundamental dynamics of fracture-fluid interactions and transform hydraulic fracturing from an ad hoc tool to a safe and predictable approach based on solid scientific understanding. Determining the key mechanisms in subsurface thermo-hydro-mechanical-chemical (THMC) systems has been impeded due to lack of sophisticated experiments that make direct 72 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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observations at (in situ) high temperatures (T), pressures (P), and stresses present in the subsurface. To address these challenges, we use unique LANL microfluidic and triaxial core flood experiments integrated with state-of-the-art numerical simulation approaches. The consequence of this work is the development of alternative fracturing fluids and fracturing techniques that enhance production, reduce waste-water, and mitigate environmental impacts (4). In this chapter we provide an overview of a variety of preliminary results based upon these experiments and simulations.

Figure 1. Shale gas processes across multiple scales.

Background Although hydraulic fracturing and horizontal drilling are changing the energy landscape, the extraction process is inefficient and poses serious threats to the environment. For example, production rates at a typical hydraulic fracturing site decline rapidly (50-60%) in the first couple of years (Figure 2), and natural gas recovery rates are also very low – usually 10–15% of the gas in place (3, 5). Furthermore, the hydraulic fracturing process requires millions of gallons of chemically treated water per well, much of which is not recovered during flow back. Whatever waste water is recovered becomes an enormous liability – it must either be re-injected at depth (potentially generating earthquakes) or be subjected to expensive wastewater treatment (6, 7). Additionally, the contaminated water that remains in the subsurface could potentially leak to drinking water aquifers through faults and natural fractures. The lack of control of the hydraulic fracturing processes adds concern of hydrocarbons leaking to the overlying aquifers or even to the surface, another significant enviromental risk. With tens of thousands of wells spread across a dozen states environmental concerns are on the rise. In conjunction, these issues have lead to a negative outlook among the public and 73 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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lawmakers. Development of shale-gas reservoirs has yet to win widespread public support, e.g., a moratorium banning hydraulic fracturing exists in New York State, because of perceived risks associated with current practices (8).

Figure 2. Average production rate for the Barnet shale play plotted as a function of years of production. All curves follow a similar trend where initial high production rates decline rapidly and are followed by lower rates. The slight increase around 6 years might be due to fracturing that occurred again. Industrial scale shale gas production using hydraulic fracturing is less than ten years old and the techniques, based on this short experience, rely significantly on aqueous fracturing fluids composed of gels, surfactants, biocides, scale and corrosion inhibitors, as well as solid particulates (proppants) to keep fractures open and maintain flow (9). Deployment in these years has been rapid and undertaken without basic research concerning effective fracturing techniques and/or determining the properties of an ideal fracturing fluid. This foundational research has been lacking because the high pressure and temperature experimental capabilities required for in situ measurements are not widely available. With regard to ideal effective fracturing techniques, fracture extent and proppant effectiveness cannot be accurately measured in the field because extraction typically occurs at depths of 2000 to 3000 meters. A combination of experience, sporadic seismic surveys, and various simulation techniques are currently used to inform fracturing operations. However, the consistency between these approaches is questionable and the high extent of uncertainty in the measurements further undermines their credibility. Because of this uncertainty, it is not surprising that only one out of three wells is profitable. Industry believes that the current state-of-the-art fracture propagation models are inadequate for highly heterogeneous layered shales and for hydraulic fractures created by fluid pressure (10). Efficacy of proppants to enhance and maintain flow in hydraulically 74 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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generated and re-activated fractures is difficult to determine as well (11). One hypothesis is that proppants settle out and do not reach many of the fractures where gas exists; slurry transport calculations in our study, in fact, support this hypothesis. It is thus possible that these anthropogenic additives, some of which are deemed carcinogenic and could potentially contaminate groundwater, may be unnecessary after all (10). Although there is speculation, the industry has yet to reach a consensus as to what makes a good hydraulic fracturing fluid. Currently, water with additives is the primary hydraulic fracturing fluid, but a lack of water in some regions and a belief that more stringent hydraulic fracturing regulations and a carbon-constrained economy are on the horizon has renewed interest in non-aqueous hydraulic fracturing fluids. A recent MIT report3 states that CO2-based fluids provide an interesting, although as yet unproven, possibility for enhancing gas recovery, reducing the amount of water required while simultaneously sequestering CO2. The use of CO2 as a hydraulic fracturing fluid, although used sporadically in the past, has shown promising results. CO2 has favorable properties over water to enhance hydrocarbon recovery (12). CO2 also exhibits more effectiveness in fracturing rock due to coupled THMC effects (13). Furthermore, CO2 is miscible with hydrocarbon and exchanges with the hydrocarbon adsorbed to shale organics. This amenable property prevents flow blocking, which is a major challenge with water. If CO2 is the base fluid, additives (such as biocides and surfactancts) might be unnecessary, but an increase in viscosity would be required if CO2 must carry proppants (14). In a few U.S. Department of Energy (DOE) sponsored experiments conducted well in the past before the natural gas boom, CO2 showed up to five times more gas production compared to aqueous fluids, required no additional toxic additives, and greatly minimized water usage. However, the results shown were not consistently positive (15–18). Within this basic research, there are highly non-linear coupled processes that play a major role, such as control fracturing and hydrocarbon extraction, and characterization of these processes is important for accurate prediction. For example, it is possible that the compressibility of CO2 will enhance rock fracturing due to a positive feedback created by thermal stresses when CO2 expands into a new fracture volume and cools the crack tip (13). Thus it needs to be determined if cycling fluid pressure can generate non-hydraulic shear fractures that remain open during the production phase when pressures are reduced. However, this requires analysis of T, P, and stress conditions using modified aqueous- and CO2-based working fluids, a task that is beyond what is currently feasible. Nonetheless, the work presented in this chapter could provide the foundational work for these important and relevant scientific questions to be addressed. We detail the various integrated experimental-modeling aspects of our work that aim at making critical measurements for determining reservoir operating conditions required to control fluid flow and fracture generation in the following sections. An overview of the experiment and modeling capabilities at different scales is presented along with a discussion of how these scales are linked. We also provide references to manuscripts written by the authors for a comprehensive discussion. Specifically, we discuss details regarding: 1) reservoir-scale modeling using a high performance computational suite based on 75 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

the discrete fracture network approach for understanding transport mechanisms and the integration of this modeling approach with data from a real shale site; 2) core-scale experiments using a tomographic triaxial system that can obtain measurements of permeability change due to fracture generation under in situ conditions; 3) microfluid experiments at high-pressure conditions for measuring sweep efficiency of water and CO2 in shale; 4) pore-scale numerical experiments using the lattice Boltzmann method to simulate gas flow.

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Reservoir Scale In contrast to the ad hoc methods currently in use, we seek a detailed analysis of the fundamental mechanics behind gas transport to better understand the reason for the rapid decline in the production. Gas production analysis is frequently done in the industry, but the methods implemented are either highly empirical or are based on simplified analytical models that depend on gross idealizations of the reservoir (19). In contrast, we simulate gas transport using advanced physics-based computational models that are built on realistic conditions utilizing well-characterized fracture datasets. Our hypothesis is that different physical and chemical mechanisms control production as a function of time (Figure 3) and we can test this hypothesis with reservoir modeling and compare our simulation results to field data.

Figure 3. A typical production from the Haynesville formation. Our hypothesis is that different physical and chemical mechanisms control production as a function of time, the primary mechanism reduces in scale at time progresses. 76 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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We use the new computational workflow dfnWorks that is built on a suite of high-performance computing (HPC) modules and visualization tools developed at the LANL and other DOE laboratories. The general workflow involves generating and meshing discrete fracture networks (DFN) using field data from geological surveys (20), solving for flow using the massively parallel subsurface simulator PFLOTRAN (21), and evaluating gas flow pathways and gas particle travel times using a unique particle tracking method developed specifically for DFN (22). In our reservoir model, a DFN is generated using fracture properties from the Pottsville shale formation in Alabama such as fracture spacing, orientation, and aperture (Figure 4). A horizontal well, colored blue, along with hydraulically generated fractures, shown in brown, is included at the center of the domain to simulate production from the reservoir. Natural fractures in the system are colored according to pressure, with red being high values (21MPa) and blue low (17MPa). Operational pressure, aperture and porosity are used in the simulation. Figure 4a shows the obtained pressure distribution in the domain highlighting drawdown towards the well. Transport pathways are determined by tracking advective nonreactive particles from locations in the DFN to the well.; trajectories of a selected number of particles are shown in Figure 4b. Further details of the computational suite and the simulation can be found in Karra et al. (23)

Figure 4. Reservoir scale calculations of the production curve. a) DFN generated base on site data from the Pottsville formation, where a well is placed at the center of the domain to simulate production. b) Draw down is created to bring methane packets, represented as particles, to the well. c) The simulation production curve (green) matches the site data (blue) for the first year and then underestimates the production rate because small scales, which govern long term production rates, are not included in the simulation. (Adapted from reference (23).) Based on the particle travel times, a production curve is obtained for the simulation (green, Figure 4c) and is compared to site production curve (blue, Figure 4c). The simulation production curve compares well to the field data especially for the first part. The tail of the simulation curve is less than that of field data. This difference in the tail is expected because the small scale transport mechanisms are not considered in our simulation (Figure 3). This comparison suggests that early production is controlled by the large hydraulic and natural fractures represented by the DFN. 77 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Our results are in line with industry observations of an early fast decline in production rates due to the drainage of hydrocarbons from the large fractures (10). Characterization of the production curve tail is critical because wells often produce for decades, and improvement of the tail will significantly impact long term production. However, the tail of the production curve is the integrated result of nonlinear combinations of 1) mass transport from the damage zone between small fractures and the shale matrix, 2) matrix diffusion, 3) desorption and 4) multiphase flow blocking – all of which have to be incorporated in our reservoirscale simulations. The work discussed in the remaining of the chapter, at the coreand pore- scales, address these complex transport mechanisms with the aim that once they are well-characterized, they can be incorporated into the reservoir scale simulator to aid in decision making.

Core Scale The knowledge gap of fundamental fracture network properties in shale is a debilitating limitation in the improvement of efficient and effective fracturing. Furthermore, core-scale (10 µm to 10 cm) fracture network processes are crucial in characterizing gas transport from intact rock matrix to small fractures that connect to the larger natural and hydraulically generated fractures, modeled as a DFN in the reservoir-scale model. To address these uncertainties we use triaxial coreflood instruments to generate and characterize fracture formation and permeability at in situ temperature, pressure and stress conditions, see Carey et al. for details (24). Figure 5 shows the experimental setup for a shear fracture experiment. These in situ tomographic measurements of fracture propagation are integrated with a finite discrete element model (FDEM) (25, 26). This integration gives a basic framework to predict fracture propagation and estimate hydrocarbon extraction under various conditions such as different fluids, rock properties, and injection/pressurization schemes. The FDEM model we have developed also simulates fracture propagation due to fluid pressure. Figure 6 compares a direct shear fracture experiment using the triaxial coreflood experimental setup with the FDEM model using a Utica shale sample provided by Chesapeake Energy. Overall good qualitative agreement is seen. Both approaches show a vertical fracture in the middle dominates the network along with two fracture arcs on each side of the vertical fracture, although, a stronger fracture system is observed in the experiments. An important lesson from this comparison is that if fluid pressure is not used or if the layers of the shale are not considered in our fracture propagation simulations, the model does not show good qualitative agreement to the experiment. This indicates that interface and fluid flow are key processes to consider in predicting fracture extent in shale.

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Figure 5. Experimental setup for a shear fracture experiment. (Adapted from reference (24).)

Figure 6. Comparison of a representative triaxial coreflood experiment (a) with the FDEM model (b) for a direct shear fracture experiment that uses a Utica shale sample provided by Chesapeake Energy. The FDEM model used generic rock material properties for Utica shale rather than properties from this specific experimental sample, with the goal being to determine if qualitative agreement between model and experiment was possible without detailed shale characterization. (Adapted from reference (24).)

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Because the permeability of shale is vital in evaluating hydrocarbon extraction but is poorly known under in situ conditions, we have developed the triaxial experiments to have the capability to measure the permeability of the shale during fracturing under in situ pressure, temperature and stress conditions. The stress and permeability as a function of strain for a shale sample is shown in Figure 7. There is no measureable permeability until failure and permeabilities up to 30 mD are measured once fractures initiate. Further deformation of the sample results in closure of fractures and healing leading to reduction of permeability.

Figure 7. Stress and permeability as a function of strain of the experiment shown in Figure 6. Initially, there is no measureable permeability. Once fractures begin to form, permeabilities up to 30 mD are measured. As the sample continues to deform under varying hydrostatic conditions the fractures begin to close resulting in fracture healing and a reduction of permeability. The permeability measurements are critical because they characterize fluid flow through shale fractured under in situ conditions. Moving forward, we are beginning to hydraulically fracture shales and are in the process of moving the triaxial experimental apparatus to a tomographic facility. This will allows us to capture in situ fracture formation images. Finally, acoustic and tracer capabilities are being appended to the experimental apparatus with a coupled flow FDEM capability concurrently being developed along with threedimensional fracture simulation capability.

Fracture-Matrix Interaction For effective hydraulic fracturing and hydrocarbon extraction, high density fracture networks at the mesoscale at the order of millimeters must be created. Although larger fractures are the major transport pathways for the hydrocarbons, a 80 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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high density fracture network of small fractures is required to increase surface area with the shale matrix and allow more methane to be liberated (27). Our approach to characterize the migration of hydrocarbon from the matrix into these small fracture networks is based on integrating microfluidic experiments with Lattice Boltzmann Method (LBM) simulations. Several key phenomena that we seek to investigate in microfluidics experiments and LBM simulations include: 1) flow blocking of hydrocarbon by residual water – on the other hand, supercritical CO2 (scCO2) may facilitate hydrocarbon migration due to its miscibility with oil and gas; 2) wettability between shale and working fluid; 3) dead-end pores can trap hydrocarbon in aqueous systems – scCO2 again will dissolve and free the hydrocarbons; and 4) some components of natural gas can condense as a liquid and block flow. At the micro-fracture scale, at the order of millimeters, we are studying two main issues: 1) the difference between glass and shale micro-models to accurately mimic sweep efficiency in shale; and 2) compare the sweep efficiency of scCO2 and water based fracturing fluids. Through these studies mass transfer in the micro-fractures will be evaluated and then upscaled for use in reservoir model simulations. Figure 8a shows the work flow for obtaining fracture geometry from a triaxial experiment, which is then used to etch the fracture pattern into a shale microfluidic wafer. We have also developed the capability to conduct microfluidic experiments under in situ high temperature and high pressure reservoir conditions. This is a critical capability for characterizing sweep efficiency because shale wetting properties are not easily replicated by synthetic materials and fluid properties are greatly influenced by reservoir temperatures and pressures. The fast flow pathway of scCO2 in a fracture that is initially filled with water is shown in Figure 8b (black). Moving on to the pore structure scale (100 nm – 100 µm), surface tension dominates fluid transport dynamics for the hydrocarbon-brine system. In addition, flow blocking due to multiphase flow could prevent effective extraction to the small scale fracture. The LBM approach is ideal to simulate these processes because it can simulate complex flows in complicated intra-pore geometries and resolve relevant physicochemical processes with high computational efficiency. As an example, we compare a microfluidic experiment with a fishbone fracture pattern shown in Figure 9a to a LBM simulation in Figure 9b. The experiment uses a sample of Utica shale. As seen in Figure 9b, the LBM simulation of the experiment is able to capture the fingering as the invading immiscible water displaces hydrocarbon. It also captures the bypassing of the hydrocarbon in dead end fractures that leads to poor sweep (Figure 9b). Although at first glance, this example appears to be a simple one, there are several complex processes and parameters that control the flow. These include: a) flow rate and fluid viscosity ratios control finger width, and b) network geometry that affects the finger width because fluid from the side channel narrows the finger. More details can be found in Middleton et al. (18)

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Figure 8. Schematic of our work-flow for extracting fracture geometry from a triaxial experiment and then etching the fracture pattern into a shale microfluidic wafer. (Adapted from reference (18).)

Figure 9. a) A microfluidic experiment in which a simple fishbone fracture pattern has been etched into Utica shale, saturated with oil and water blocking the exit. b) A LBM of the experiment. The simulation captures the fingering as the invading immiscible water displaces hydrocarbon, but bypasses the hydrocarbon in dead end fractures resulting in poor sweep. 82 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Acquiring and imaging shale samples for use in LBM simulations is also a challenge due to the length scales in shale that must be resolved (28). To make matters worse, numerous shale samples are required to obtain statistics with tight confidence intervals. An alternative approach is to stochastically generate samples with desired properties. On the left side of Figure 10 is a binarized image of a shale and the image on the right is generated to have similar statistical properties as the rock sample using the techniques of Hyman and Winter (29). The algorithm to generate these samples is fairly computationally fast and can generate a large number of them quickly. Another important factor that increases the permeability of shale is crack density, which leads to improved gas migration from kerogen to damage zone (27). Characterizing and evaluating the permeability change due to cracks is done by including fractures into synthetic pore structures similar to Figure 10b.

Figure 10. Left) A two-dimensional slice of a binary image of shale where black is higher permeability organic inclusions. Right) A synthetic sample generated to have the similar statistics, namely geometric observables, as the image on the left.

Figure 11a shows a representative example, where we generate a synthetic medium based on an image of shale, and a solved linear diffusion equation for pressure therein. Dark grey represents low permeability in-organic material, while the white region is higher permeability organic material. Pressure contours obtained from the diffusion solver are shown in color. Flow velocity is represented using arrows whose length is proportional to the magnitude of the velocity vector. In Figure 11b we have included four micro-cracks into the same shale structure and determine the difference in effective permeability. Merely including these four cracks that are aligned with the pressure gradient into the system nearly doubles the effective permeability of the sample! We are further investigating this dependence of effective permeability on crack density based on this novel methodology. 83 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 11. Preliminary investigation into the influence of microcracks on permeability. A pressure gradient is imposed to determine flux, and therefore permeability. Contours denote pressure. The underlying geometry of both samples are identical, but the sample in (b) has four high permeability micro-cracks. The sample in (b) has an effective permeability that is nearly double that of the sample in (a).

Pore Scale The physics occurring at the scale of individual pores (10-100 nm) in shales is remarkable because the length scales involved are so small that standard diffusion breaks down. Specially, the mean free path of a gas particle is larger than characteristic pore size of the medium and unrestricted Brownian motion cannot occur. When the Knudsen number (Kn), the ratio of the mean free path of a gas particle over the characteristic pore size of the medium, is relatively large, gas molecules tend to slip on the pore walls and the effective permeability of the medium can be significantly larger than the intrinsic permeability of the medium. This influence is known as the Klinkenberg effect. The effect of this gas slippage on permeability in shales was recently studied by Chen et al. (30), using our LBM simulations. The authors determined that a significant deviation from the intrinsic permeability occurs due to gas slippage. Figure 12 shows how the permeability of a medium is underestimated if the Klinkenberg effect is not included. If it is neglected, then estimations of permeability can differ by up to two orders of magnitude. This influence is more pronounced at low pressures.

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Figure 12. Relationship between global permeability and porosity, plotted at three different pressures and without consideration of the Klinkenberg effect. If the Klinkenberg effect is not included permeability is underestimated, more so at low pressure.

Conclusions In this chapter, we have described several scientific approaches developed to improve our understanding of the complex processes associated with hydraulic fracturing. First, we described a novel reservoir scale discrete fracture network model that forms as a framework to determine the key physical mechanisms governing the initial decline in natural gas production. Next, we described our approach at the core-scale with triaxial experiments to focus on understanding fracture-permeability behavior and compared it to FDEM modeling of fracture propagation. We benchmarked these triaxial measurements with FDEM model and will upscale the results to the near wellbore environment. Using a high-pressure/temperature microfluidics experiments conducted in shale micro-models, our aim was to extract the details of pore-scale multiphase flow processes within fractures. These details lead to evaluating sweep efficiency of the working fluid which will help the community to design more effective working fluids for the recovery of hydrocarbons. Additionally, by simulating 85 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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these results with the LBM approach, we extended the experiments to consider a wider spectrum of conditions and potential working fluid properties. The goal of this integrated experiment-simulation approach is to expose how differing stress conditions and shale properties govern fracture growth, penetration, and hydrocarbon extraction. The results of pore- and core-scale experiments and simulations provide basic characterization of fracture properties that will be used to populate the reservoir-scale DFN model. This large-scale simulation reveals the mechanics of how processes within the matrix, fracture damage zone, fine-scale fracture network eventually drain to the dominant fracture network connected to the horizontal wellbore. By using field data, we will relate these results to actual production curves with the aim to provide critical data on the efficiency of hydraulic fracturing. The integration of multi-scale experimental measurements and computational modeling of coupled THMC systems is critical to understand and eventually control fracture formation due to fluid flow in the hydraulic fracturing process. Such results provide key insights into the physics behind the complex processes that can lead to more efficient hydrocarbon extraction. More efficient wells lead to a smaller environmental footprint, and improved understanding of fracture generation and propagation leads to better control and containment of fractures in the shale layer. Furthermore, these results increases confidence in the protection of groundwater resources close to the shale layer.

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President Obama State of the Union Address 2012, “We have a supply of natural gas that can last America nearly one hundred years, and my Administration will take every possible action to safely develop this energy. Experts believe this will support more than 600,000 jobs by the end of the decade. And I’m requiring all companies that drill for gas on public lands to disclose the chemicals they use. America will develop this resource without putting the health and safety of our citizens at risk. The development of natural gas will create jobs and power trucks and factories that are cleaner and cheaper, proving that we don’t have to choose between our environment and our economy. And by the way, it was public research dollars, over the course of thirty years, that helped develop the technologies to extract all this natural gas out of shale rock - reminding us that Government support is critical in helping businesses get new energy ideas off the ground.” Begos, K., Associated Press, Aug. 16, 2012. “In a surprising turnaround, the amount of carbon dioxide being released into the atmosphere in the U.S. has fallen dramatically, to its lowest level in 20 years, and government officials say the biggest reason is that cheap and plentiful natural gas has led many power-plant operators to switch from dirtier-burning coal.” Moniz, E. J.; Jacoby, H. D.; Meggs, A. J. The Future of Natural Gas; MIT: Cambridge, MA, 2012.

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Chapter 4

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Naturally-Occurring Radioactive Materials (NORM) Associated with Unconventional Drilling for Shale Gas Andrew W. Nelson,1 Andrew W. Knight,2 Dustin May,3 Eric S. Eitrheim,2 and Michael K. Schultz1,4,* 1Interdisciplinary

Human Toxicology Program, University of Iowa, Iowa City, Iowa 52242, United States 2Department of Chemistry, University of Iowa, Iowa City, Iowa 52242, United States 3State Hygienic Laboratory, University of Iowa, Coralville, Iowa, 52241, United States 4Department of Radiology, Department of Radiation Oncology, Free Radical and Radiation Biology Program, Medical Scientist Training Program, Biosciences Program, University of Iowa, 500 Newton Road, ML B180 FRRB, Iowa City, Iowa 52242, United States *E-mail: [email protected]

As unconventional drilling has emerged as a major industry in the U.S. and around the world, many environmental health and pollution risks have surfaced. One emerging concern is the risk of environmental contamination arising from unconventional wastes that are enriched in naturally-occurring radioactive materials (NORM). Although NORM has been a well-documented contaminant of oil and gas wastes for decades, there are new challenges associated with unconventional drilling. This chapter will present the origin of NORM in black shale formations. In addition, we present the fundamentals of radioactive decay and ingrowth, so as to provide a foundation for a discussion of the potential for environmental impact of NORM. Finally, within this context, we highlight key-relatively-unexplored aspects of unconventional drilling that point to the need for further environmental radiochemistry research.

© 2015 American Chemical Society In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch004

Introduction Hydraulic fracturing and horizontal drilling for shale gas has emerged as an important technology for supplying energy to the United States and the rest of the world (1–3). Amongst its benefits (for example, reduced land impact compared to conventional natural gas (4), lower direct CO2 emissions than coal (5), etc.), unconventional drilling has many unknown and uncharacterized potential environmental pollution risks (6–14). Of the least characterized environmental pollutants generated by new natural gas extraction techniques are naturally-occurring radioactive materials (NORM) (15). At depth, gas-bearing formations such as the Marcellus Shale (northeastern United States), often contain elevated levels of NORM, relative to the terrestrial environment at the surface (16); Thus, the identification of elevated levels of NORM is frequently used as an environmental marker of petroleum rich reserves and used to guide drilling operations (17). However, as mining operations proceed to the extraction stage of well development, the relative enrichment in NORM in these materials has the potential to result in co-extraction of these NORM (often referred to as “technologically-enhanced naturally occurring radioactive materials” (TENORM) (18). Co-extraction has the potential to lead to environmental contamination, bioaccumulation of radionuclides and radiation exposure to humans that would have otherwise been confined at depth. Thus, the proliferation of new horizontal drilling and hydraulic fracturing practices and technologies is leading to challenges associated with management of NORM. Some of these challenges, such as management of produced fluids, disposal of solid waste, and bioaccumulation of contaminants from oil and gas operations are well known from off-shore drilling operations (19, 20). Other challenges are new and uncharacterized as drilling technologies originally developed for offshore operations are brought into the interior of the country (1). Developing understanding of and management strategies for NORM in these uncharacterized wastes will require input from interdisciplinary teams comprising specialists in industrial hygiene, toxicology, health physics, epidemiology, geology, petrology, atmospheric chemistry, environmental and civil engineering, policy, sociology, and radiochemistry. As radiochemists, our goal is to provide accurate and precise models of past, present, and future levels of radioactivity concentrations to inform appropriate waste management decision-making. Three related concepts are critical to understanding radioactivity concentrations in relation to NORM liberated by unconventional oil and gas mining: (1) geochemical partitioning of radionuclides in the natural decay series; (2) the resulting potential for disruption of natural steady-state radioactive decay relationships in the decay series (referred to as disequilibrium); and (3) the subsequent radioactive ingrowth that occurs after a disequilibrium event. To explain the concept of partitioning, we introduce the physicochemical properties of NORM and how these properties can result in geochemical partitioning (disequilibrium) of specific NORM in solid, liquid, and gas phases. Next, we describe radioactive ingrowth to explain how the radioactivity concentration of radioactive wastes have the potential to increase over time after a disequilibrium event. We conclude with a discussion on the major phases of drilling as they 90 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

relate to radioactivity and provide three research areas that are relevant to environmental public health. Thus, the goal of this perspective is to highlight some of the known challenges and to guide future investigations in environmental radioactivity related to unconventional drilling, with the goal of informing appropriate decision-making for waste management.

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NORM The observation that certain elements are naturally-radioactive dates back to 1896, when Henri Becquerel discovered that uranyl-sulphate crystals spontaneously emitted radioactivity similar to X-rays (21). Madame Marie Curie later observed that all uranium and thorium isotopes were radioactive regardless of their chemical composition (22, 23). She also observed that uranium-containing mineral pitchblende possessed a higher level of radioactivity than compounds prepared from recently purified uranium. This observation prompted Marie Curie and her husband (Pierre Curie) to purify pitchblende and to characterize many of the radionuclides that are now collectively referred to as NORM. Many of the chemical properties that allowed the Curies to separate the various elements are important factors in environmental partitioning. We have provided a brief description of the physicochemical properties of the elements that comprise NORM so as to provide a basis for the subsequent discussion on environmental partitioning (see Addendum: Basic Properties of NORM). We restrict our discussion to elements and isotopes from the three primordial decay series: (1) the actinium (235U) series, (2) the thorium series (232Th series), and (3), the uranium series (238U series, sometimes referred to as the radium series). Note, that another important natural isotope 40K (t1/2 = 1.248 x 109 years) can be considered TENORM (24). 40K will be present in all natural sources of K with a natural abundance of 0.0117% (25). Each of the primordial decay series is supported by an isotope with an extremely long half-life (235U, 7.04 x 108 y, 232Th 1.4 x 1010 y, 238U 4.47 x 109 y) (25). Each of the three primordial NORM decay series noted above comprises a radiogenic ‘progenitor’, which supports a series of ‘progeny’ radionuclides with varying half-lives (μs to millions of years) and different physicochemical properties (gas, particle reactive, redox sensitive, etc.). In total amongst the three decay series there are 41 radionuclides from 12 different elements, where each radionuclide has unique decay modes and half-life, and each element has unique chemistry (26). Note, due to these physicochemical and radiochemical properties, each isotope has a different detection strategy (Table 1). All three of these decay chains will ultimately decay to one of three stable lead isotopes (208Pb, 207Pb, and 206Pb) (Figure 1) (21). In general, the specific activity (radioactivity per gram of natural material; e.g., soil, sediment) of radionuclides in the actinium series is substantially lower than the specific activity of 232Th and 238U series radionuclides – owing to the low natural abundance of 235U (0.7% the mass of natU) (25). Thus, we focus on NORM in the 238U series (14 radionuclides, 8 elements) and 232Th series (11 radionuclides, 8 elements) (26).

91 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 1. The primordial decay series of interest in shale formations: actinium (235U) series (left), uranium (238U) series (middle), and thorium (232Th) series (right). All half-lives are from the National Nuclear Data Center (NuDat).

92 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Table 1. Naturally Occurring Radioactive Materials of Interest in Unconventional Drilling Wastes Element

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Element Uranium (U)

Protactinum (Pa)

Thorium (Th)

Isotopes

Expected forms U4+ reduced, particle reactive, expected in shale formation; U6+ oxidized, mobile, expected to form under some conditions at the surface of the earth Pa5+ particle reactive

Th4+ particle reactive

α/β/γ

a

Half-life

S/L/G

b

Isotopic Detectionc

238d

α

4.468x109 y

S

MS, AS, HPGe (234Th, 234mPa)

235

α, γ

7.04x108 y

S

MS, AS, HPGe

234d

α

2.455x105 y

S

MS, AS

234m

γ

1.159 m

S

HPGe

234

β

6.7 h

S

HPGe (234mPa)

234

β, γ

27.1 d

S

MS, HPGe

232

α

1.4x1010 y

S

MS, AS

230

α

75,400 y

S

MS, AS

228d

α

1.9116 y

S

AS

Actinium (Ac)

Ac3+ particle reactive

228

β, γ

6.15 h

S/L

HPGe

Radium (Ra)

Ra2+ soluble at depth and surface, solubility dependent on salinity and chemical matrix

228d

β

5.75 d

S/L

HPGe (228Ac)

226d

α, γ

1600 y

S/L

HPGe (direct or 214Bi, 214Pb)

224d

α, γ

3.6319 d

S/L

HPGe (direct or 212Bi, 212Pb) Continued on next page.

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Table 1. (Continued). Naturally Occurring Radioactive Materials of Interest in Unconventional Drilling Wastes Element

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Element Radon (Rn)

Polonium (Po)

Bismuth (Bi)

Lead (Pb)

Isotopes

Expected forms Rn, nobel gas

Po2+, Po4+ unclear which form, particle reactive

Bi3+

Pb2+

particle reactive

particle reactive

a

Half-life

S/L/G

b

Isotopic Detectionc

222d

α

3.8235 d

S/L/G

Emanation

220

α

55.6 s

S/L

Emanation

218

α

3.098 m

S/L/G

N/A

216

α

0.145 s

S/L

N/A

214

α

164.3x10-6 s

S/L/G

N/A

212

α

0.299 x

10-6

S/L

N/A

210d

α

138.376 d

S/L/G

AS

214

β, γ

19.9 m

S/L/G

HPGe

212

β, γ

60.55 m

S/L

HPGe, AS

210

β

5.012 d

S/L/G

N/A

214

β, γ

26.8 m

S/L/G

HPGe

212

β, γ

10.64 h

S/L

HPGe

β, γ

22.2 y

S/L/G

HPGe

210d a (α) alpha-emitter;

α/β/γ

s

b (S) expected to be present and/or generated in solid wastes (bit cuttings);

(β) beta-emitter; (γ) gamma-emitter. (L) expected to be present and/or generated in liquid wastes (flowback/produced fluids); (G) expected to be present and/or generated gas streams (flared-waste gases and natural gas). c (MS) mass-spectrometry; (AS)alpha-spectrometry; (HPGe) high purity germanium gamma-spectrometry Emanation—radon emanation. d key isotopes of interest in environmental fate and transport.

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

NORM in Marine Black Shales

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The term “shale” generally refers to fine-grained-sedimentary clays and rocks that have widely differing biogeochemical morphologies and geologic ages (27). The types of shale of most interest to the petroleum and natural gas industries are the so-called, “black shales,” which are sedimentary rock deposits that became enriched in organic materials and metals originating from marine or brackish water (28). Black shales are characteristically dark in color owing to enrichment of organic content (which in some cases may exceed 10%) via multiple biogeochemical processes (Figure 2) (29, 30). Over millennia, different biogeochemical processes (thermogenic and microbial), resulted in the reduction of the various organic materials into methane (natural) gas (31).

Figure 2. Uranium (U) trapped in marine organisms and sediments as an explanation for the increased levels of U and U decay products in marine black shale formations. The relatively high level of organic content in black shales is important not only for the production of natural gas, but also has implications for enrichment of NORM. The marine environment from which black shales typically arise are enriched in natural U isotopes (natU: 238U, 235U, 234U), with an average of 3.3 μg natU/L depending on ocean salinity in which the sediment was formed (32). While natU behaves conservatively in oxic marine environments resulting in a conservative natU and salinity correlations, this dissolved natU is 95 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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concentrated in organic-rich ocean sediments (for example, black shales) by the following mechanisms: (1) inorganic precipitation as U-rich marine waters pass across suboxic, organic-rich sediments (33), (2) microbiological reduction and immobilization of natU (34), and (3) sedimentation of marine organism detritus (35). As hexavalent uranyl (UO22+) is reduced to tetravalent (U4+) at the anoxic/oxic boundary, insoluble complexes/minerals are formed that lead to enrichment of U in black shales (35). Thus, over millions of years, black shales are enriched in U and radioactive decay products in the U-series and are likely to be found in steady-state radioactive equilibrium with long-lived progenitors (26, 36). Thus, at depth in the formation, one can expect that the decay rates of primordial progenitors and radioactive progeny are essentially the same (in secular equilibrium). On the other hand, anthropogenic activities, such as natural gas and petroleum mining in these formations have the potential to disrupt these steady state conditions by co-extraction of specific radionuclides in the primordial series – i.e., partitioning of the specific progeny into the extracted liquid and gas phases in the mining process. Although shale formations vary in mineral composition and age, one can describe four overarching biogeochemical properties that can be used to predict the likely behavior (partitioning) of radionuclides from formations at depth: (1) Formations are generally ancient (fossil, > 100 million years old, particularly in the case of the Marcellus Shale), suggesting that radioactive decay products are present and in equilibrium with the supporting progenitor (37); (2) Formations are likely anoxic, reducing environments at depth (38). This has direct implications for the fate and transport of select redox-sensitive radionuclides (e.g., U, Po) and indirect implications by altering the key adsorptive surfaces (for instance, Mn and Fe minerals) (39–41); (3) At depth, microbial reduction of sulphate (SO42-) to form sulfides (H2S, S2-) enhances the solubility of heavier alkaline earth metals (Sr, Ba, Ra). The implication is that in environments low in sulphates, there is a higher probability that Ra will be soluble (RaSO4 Ksp = 4.25 x 10-11) (42) as evidenced by low SO42- brines from the Marcellus Shale region having high levels of Ra isotopes (43–46); and (4) Interstitial fluids in some black shales (Marcellus Shale in particular) are likely high in salinity, which creates conditions that enhances the solubility of Ra (47, 48).

Partitioning in the Subsurface Based on our investigations of NORM in Marcellus Shale produced fluids we developed a general model to predict partitioning of U-series and Th-series progenitors and radioactive progeny between solid-phase materials (bit cuttings; solid waste generated by drilling) and interstitial brine (flowback/produced fluids) extracted through the unconventional drilling/hydraulic fracturing process. To illustrate the principles of our generalized model, we describe the partitioning of the radionuclides in these series at depth by examining the physico-chemical events that govern the biogeochemical behavior of the radionuclides in these series. We begin with a single atom of apical progenitors 238U and 232Th, and 96 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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examine differences in geochemistry and decay modes that govern the separation of progenitors and radioactive progeny (Figure 3).

Figure 3. Theoretical partitioning model of U and U decay products at depth in shale formations. (Adapted with permission from reference (63)). Uranium Series Partitioning at Depth Owing to the geologic history and chemically-reducing conditions of the Marcellus Shale, one can expect 238U (t1/2 = 4.5 x 109 years) to be contained in the crystal lattice of minerals in a reduced-immobile (U+4) oxidation state (35). As 238U decays by alpha-particle emission to 234Th, it imparts a large amount of energy (often referred to as alpha recoil energy) to the Th nucleus. Alpha recoil energy is sufficient to break chemical bonds in the crystal structure of the rock (49), potentially leading to enrichment of the 234Th atoms located at the solid-phase interstitial aqueous-brine interface (26, 50). Although the geochemistry of Th is not susceptible to changes in oxygen concentration that might arise under environmental conditions, Th is known to be highly particle reactive. These properties predict Th to be relatively immobile via adsorption to mineral surfaces at depth in shale formations (51). Thus, the reducing environment of the Marcellus Shale and particle reactivity of Th predict that U and Th radionulclides are likely to be relatively immobile and unlikely to be extracted into aqueous-phase hydraulic fracturing fluids used for natural gas mining (34, 52). Conversely, radioactive decay of solid-phase bound 230Th results in 226Ra species that are much more soluble in the interstitial brine due to low sulfate concentrations and high salinity of Marcellus Shale formation water. The decay of 226Ra leads to the formation of the radioactive noble gas 222Rn, which adds complexity to predictions of the fate of successive decay products. Because 222Rn is an inert gas with a half-life of nearly four days, gaseous diffusion and partitioning of 222Rn (and its subsequent decay progeny) from 226Ra 97 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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via diffusion through fissures created by hydraulic fracturing events is possible (53). In general, 222Rn only travels 0.1 m in wet soils by diffusion alone, but long-range transport is possible when coupled with a carrier fluid (54). Given that 222Rn has increased solubility under high pressure at depth, it is likely that 222Rn will be contained in the interstitial fluids of the formation only to decay through a series of short-lived isotopes to insoluble radioactive decay product 210Pb (t1/2 = 22.2 years) (54). More research is needed to determine the effects of the divalent-rich saline environment on the solubility of 222Rn (55). Careful sample preparation and measurements of flowback water and produced fluids from hydraulic fracturing at the time of extraction have the potential to elucidate more precisely the radioactive steady-state/non-steady-state relationship of 226Ra and progeny 222Rn in liquid waste products of unconventional drilling. Differences in the geochemistry of 210Pb and 226Ra have provided an opportunity to develop a temporal understanding of geochemical phenomena for decades (56). However, as 210Pb decays to the redox active element, 210Po, the fate of 226Ra progeny becomes less clear. Studies of anoxic marine environments suggest that 210Po can partition from 210Pb and concentrate in organic rich particulate phases (57). Other studies show that under low-oxygen conditions, 210Po is particle reactive and its transport is associated with the migration of Fe or Mn minerals (40, 57–59). Although it is currently unknown whether reagents used in hydraulic fracturing fluids will mobilize 210Po, its transport in the subsurface will likely be coupled with changes in redox conditions, pH, and bulk movement of Fe- and Mn-containing particulates. Given that 210Po and 210Pb can separate from one another under certain environmental conditions (60), researchers should measure 210Pb and 210Po independently. Use of 210Po levels as a proxy for 210Pb radioactivity concentrations may not be appropriate. The potentially high levels of 210Po in unconventional drilling wastes present a unique opportunity to study fundamental 210Po processes at depth and in the terrestrial environment. For example, future studies could focus on the possible relationships between microorgamisms, sulfur-cycling, and polonium partitioning (61). Thorium Series Partitioning at Depth The fate and transport of the 232Th series is similar to the previous discussion of the 238U series. The progenitor radionuclide, 232Th (t1/2 = 1.4 x 1010 years), is insoluble in environmental waters and brines. As 232Th decays by alpha emission to 228Ra (t1/2= 5.75 years), the resulting 228Ra progeny is soluble in the sulphatedeficient, divalent-rich brine. As 228Ra decays to 228Ac (t1/2 = 6.15 hours) by beta emission, the fate is uncertain. Generally, Ac forms insoluble complexes and quickly adsorbs to mineral surfaces, but given its short half-life it can be difficult to discern the exact mechanism (62). Then 228Ac decays by beta emission to the insoluble 228Th (t1/2 = 1.91 years). Note, the large difference in solubility for 228Ra and 228Th gives rise to a chronometer (transient equilibrium model) that has potential to assist in determining the time when samples were removed from the Marcellus Shale (63). The nucleus then undergoes decay to form 224Ra (t1/2 = 3.63 days), which again solubilizes into the brine. 220Radon (t1/2 = 55.6 s) then decays by alpha emission to form 216Po (t1/2 = 0.145 s), which rapidly emits another alpha 98 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

particle to form 212Pb (t1/2 = 10.64 hours). Similar to 210Pb in the 238U decay series, 212Pb is expected to be insoluble and particle reactive. Next, 212Pb decays by beta emission to 212Bi (t1/2 = 60.55 min), which is also likely insoluble (64). Then 212Bi branches to two different decay products; 64% of decays are by beta emission to form the very short-lived 212Po (t1/2 = 0.299 μs) while the other 36% of decays form 208Tl (t1/2 = 3.053 min) (25). Both 212Po and 208Tl decay, by alpha and beta particle emissions respectively, to 208Pb (stable).

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Radioactive Decay, “Equilibrium”, and Ingrowth This section describes the fundamental properties (decay, equilibrium, ingrowth) of radioactive materials and how these properties relate to unconventional drilling wastes in general. Radioactive Decay Radioactivity (A) is a measurement of the number of decaying atoms in a sample in a given period of time. Radioactive decay of any given atom is a spontaneous event; however, mathematical models can predict the decay rate of large groups of atoms (N) of the same isotope. It is observed that isotopes decay by first order kinetics at a rate related to their half-life (t1/2) according the following equations (eq.: 1-3):

Within the context of NORM, progenitor atoms decay by alpha particle (charged helium nucleus, 4He2+, α) or beta particle emissions (electron, β-) to form progeny atoms. After one half-life, exactly 50% of the progenitor of radioactive atoms will exist. After two half-lives, exactly 25% of the progenitor atoms exist. After three half-lives, exactly 12.5% of the progenitor atoms remain. And the pattern continues, such that after every half-life, the continual radioactive decay results in exactly 50% of the remaining progenitor atoms having decayed by the time the next half-life begins. This concept is the foundation for describing the decay of a single radioactive element. However, when considering a radioactive decay series, the radioactive-progenitor atom decays to a radioactive-progeny atom, which in turn, decays to a radioactive-second-progeny atom. This pattern 99 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

continues with progenitors providing the input of atoms to progeny and the progeny providing the input of atoms for successive progeny, until reaching a stable decay product. This relationship can be quantified by a differential equation described by Bateman in 1910 (65).

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Radioactive Equilibrium For the purposes environmental monitoring, the concentration of progeny, second progeny, or atom further along in the decay series may be of more interest than the progenitor. For instance, the concentrations of 226Rn (t1/2 = 1600 y), 222Rn (t1/2 = 3.824 d), 210Pb (t1/2 = 22.2 y), 210Pb (t1/2 = 138.4 d) may be of greater interest in the natural gas industry than the progenitor, 238U (t1/2 = 4.5 x 109 y). In a closed system that has not been disturbed for millions of years (such as in an ancient, fossil shale formation at depth) the radioactivity concentrations of 226Ra and 222Rn are in radioactive “equilibrium” (steady state) with the progenitor, 238U, where the radioactivity associated with 226Ra, 222Rn and 238U are equal. However, during an event where this closed system is disturbed (such as unconventional drilling to extract natural gas) the physicochemical differences of certain NORM can result in a radiochemical “disequilibrium” (non-steady state), where the subsequent progeny radioactivity concentrations are not equal to the progenitor. During a disequilibrium event, progeny may partition from progenitor atoms, as well as other progeny atoms further in the decay chain. For instance, 226Ra experiences elevated solubility in shale formations in hydraulic fracturing flowback water, while its progeny (222Rn, 210Pb, 210Po) and supporting atoms higher in the decay chain (238U, 234Th, 234Pa, 234U, 230Th) remain insoluble, resulting in partitioning of 226Ra from its progenitors and progeny (63). Given that the progenitors have been removed, the radioactivity of 226Ra will decrease at the rate of its half-life (1600 y). Because 226Ra is unsupported by its progenitor radionuclides, its decay can be modeled using the basic radioactive decay equation described above (eq. 2). However, the activities of the progeny (including 222Rn, 210Pb, 210Po) will increase through a process known as radioactive ingrowth. Radioactive Ingrowth Radioactive ingrowth is important to consider when estimating the long-term risks associated with radioactivity liberated by unconventional drilling (63). The most precise way to describe radioactive ingrowth is through derivations of the Bateman equation (eq. 6 & 7), yet in practice, there are two scenarios where simplification of the Bateman equation may prove useful: secular equilibrium and transient equilibrium. Secular equilibrium refers to a closed-system scenario in which the half-life of a supporting isotope is much longer than the decay product (e.g., 226Ra: t1/2 = 1600 y; and 222Rn: t1/2 = 3.824 d). Immediately after a partitioning event that results in disequilibrium, time (t0), the progeny (222Rn) will begin to grow in at a rate determined by its own half-life until it equals the activity of the supporting atom (226Ra). Note, the progeny will grow into equilibrium with the progenitor with an activity ratio of 1:1, but the atomic ratio will not be 1:1 as this ratio related to half-lives (eq. 4): 100 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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When the activities of the two nuclides become equal, which occurs after approximately 6-10 half-lives of the progeny (e.g., ~30 days for 222Rn and ~150 years for 210Pb, Figure 4A and 4B), the progeny is said to be in secular equilibrium with the progenitor (e.g., 226Ra). This relationship can be modeled using a simplified secular equilibrium equation (eq. 5):

In contrast, transient equilibrium refers to a scenario in which the half-life of the progenitor is only slightly greater than that of the decay product (e.g., 228Ra, t1/2 = 5.75 y; and 228Th, t1/2 = 1.91 y). In this case, as with secular equilibrium, immediately after a partitioning event that results in disequilibrium, time (t0), the progeny (228Th) will begin to grow in at a rate related to its own half-life (21). However, the progenitor (228Ra) in this case is decaying on a time scale of similar magnitude as the progeny, and although the activity of the progenitor is initially larger than the progeny (228Th), over time the activity of the progeny will exceed the activity of the progenitor (Figure 4C). The significance of this phenomenon is that several years after disequilibrium occurs, the activity of 228Ra will be less than the activity of its decay products (228Th, 224Ra, 212Pb, 212Bi in particular). Note, 228Th (228Th t1/2 ≫ 224Ra t1/2) will then support subsequent progeny in the decay series (Figure 4D). This relationship between 228Ra and 228Th can be modeled using a simplified transient equilibrium equation (eq. 6):

Although these simplifications may be useful to explore the relationship between any two isotopes in a series, they are limited when modeling the complete decay series is desired. For instance, if concentrations of 210Pb and 210Po (decay products of 238U) or 228Th and 224Ra (decay products of 232Th) are needed, then the Bateman equation must be used. The following equations (eq. 7 & 8) can provide the radioactivity concentrations of any decay product in any decay series using standard spreadsheet software: 101 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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By assuming that the activities/atoms of decay products are zero at some starting time, (t0), one can easily model how long it will take each decay product to reach “equilibrium” with a progenitor. For example, when hydraulic fracturing flowback fluids are initially captured at the surface of the earth they are enriched in 226Ra. Investigations from our laboratory indicate that decay products may be absent from the flowback; however, given the nature of radioactive materials the decay products will ingrow (63). By modeling 226Ra-decay product ingrowth using the Bateman equation, we can show that 222Rn activities steadily ingrow, approaching equilibrium in ~30 days (in a closed-system where 222Rn cannot escape). The decay products of 222Rn with short half-lives (218Po, 214Pb, 214Bi, 214Po) quickly follow the ingrowth of 222Rn. The result is that the total radioactivity due to 226Ra and its decay products will increase by a factor of approximately six in 30 days as the short-lived progeny approach secular equilibrium with 226Ra (Figure 4E). Further, the total radioactivity will continue to increase for nearly 100 years as the long-lived 210Pb grows into the sample (Figure 4F). The 210Bi will relatively quickly establish equilibrium with 210Pb since it has a relatively short half-life. The final radioactive decay product in the series— 210Po — with a half-life of 138.4 days takes approximately 3 years to reach equilibrium with 210Pb and will then will continue to increase until establishing secular equilibrium with 226Ra. Although this theoretical discussion of a closed-system is useful for illustrating how radioactivity behaves, closed-system models may not be suitable for environmental systems. Shale formations at depth likely behave as a closed-system, until disturbed by unconventional drilling. The drilling process is quite extensive and comprises multiple stages that generate, reuse, or dispose of large volumes of solid or liquid materials that open the system to different environmental conditions.

102 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 4. Equilibrium characteristics of selected NORM after a disequilibrium event as modeled by the Bateman equation. (A) 222Rn grows into secular equilibrium with 226Ra in less than 30 days. (B) 210Pb grows into secular equilibrium with 226Ra after 100 years. (C) 228Th establishes transient equilibrium with 228Ra. (D) 224Ra approaches secular equilibrium with 228Th. (E) 226Ra decay products increase total radioactivity approximately 6-fold within 30 days. (F) Activity of 226Ra decay products increase for more than 100 years formations. (Adapted with permission from reference (63)).

103 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Major Stages of Unconventional Drilling

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Unconventional drilling can be broken down into six major stages, including: (1) water acquisition, (2) chemical mixing, (3) drilling, (4) injection of hydraulic fracturing fluids, (5) releasing well pressure (flowback/produced fluids and gas flaring), and (6) treatment or storage of liquid and solid wastes (Figure 5) (66). Each of these stages has distinct characteristics and environmental considerations that help determine which radionuclides to expect throughout the drilling process.

Figure 5. Major stages of unconventional drilling as they relate to environmental radiochemistry. Water Acquisition One hallmark of unconventional drilling operations is the tremendous volume of water required (67, 68). Some operations in the Marcellus Shale region (Eastern US) have been documented to use up to 40,000 m3 of water for a single fracture (16). Unsurprisingly, the potential for straining fresh water resources is a concern, particularly at the local scale and in the arid Western US (69). In addition to these concerns, the cost of acquiring water has led many operators to pursue new wastewater purification technologies that allow for the reuse or recycling of flowback/produced fluids (70). One drawback with reusing such fluids is that flowback and produced fluids may be enriched in Ra isotopes (43, 44). Although some of the treatment technologies may remove Ra isotopes, they may not simultaneously remove other NORM (71). For recycling technologies to effectively remove radioactivity from produced fluids, they must consider the nature of radioactive ingrowth. Undertreated/untreated recycled fluids may contain 228Ra-decay products such as 228Ac, 228Th, 220Rn, 212Pb, 212Bi, 208Tl and 226Ra-decay products such as 222Rn, 214Pb, 214Bi, 210Pb, and 210Po. 104 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Chemical Mixing A major source of controversy surrounding unconventional drilling in the United States is the large volume of unspecified chemicals used in hydraulic fracturing fluids (72). At the federal level in the United States, these chemicals and chemical blends have largely been exempted from disclosure due to trade secret protection (73). In recent years many companies have identified the majority of the chemicals, which are listed well-by-well in publicly accessible databases (for example, FracFocus.org) (74). Some of the disclosed constituents of fracturing fluids (including acids, reducing agents, organics, chelators) are known to interact with NORM (72). For example, uranium mobility is enhanced when complexed with citrates—a known constituent of hydraulic fracturing fluids (75). Additionally, hydraulic fracturing fluids are acidified with hydrochloric acid (11), a reagent that is commonly used in laboratories to solubilize NORM. Without detailed information on the chemicals introduced to the formation, it is difficult to predict how NORM will interact when it comes in contact with hydraulic fracturing fluids. Further, the complexity, quantity, and diversity of chemical blends used as hydraulic fracturing fluids suggest a case-by-case analysis of each well is necessary. Drilling Drilling operators have used gamma-ray-log-detectors for decades to find target formations due to the well known correlation between gas productivity and radioactivity (76). Historically, natural gas wells were vertical (conventional well), and thus only a relatively small portion of the well was in the target formation of higher radioactivity. Advances in horizontal drilling now allow operators to drill down and laterally through the formation for thousands of meters (1). The result is significantly larger surface area of the unconventional well in the formation in comparison to conventional, vertical wells. In order to make space for the well, material must be removed from the depth. The material that is removed is referred to simply as “cuttings (77),” or commonly as bit cuttings or drill cuttings. Although values vary from well-to-well, one report indicated a single horizontal well may produce 250,000 kg of bit cuttings (77). Since a large portion of these bit cuttings comes from the higher radioactivity formation, the bit cuttings can be expected to be enriched in radioactivity. A recent report indicates that radioactivity concentrations of 238U in vertical cuttings were between 40 and 70 Bq/kg, whereas concentrations in horizontal cuttings exceeded 300 Bq/kg (78). Horizontal bit cuttings can similarly be expected to be enriched in insoluble U-series decay products, such as Pa, Th, Po, and Pb isotopes. Injection Once the well has been drilled and the casing has been installed, hydraulic fracturing fluids are pumped into the well at tremendous pressures (up to 800 kPa) (11). In some cases industry will inject radioactive tracers into the well to check for inter-well connectivity or to measure flow rates (79). Most of the radioactive 105 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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materials used at this stage are gamma-emitting radionuclides that decay to a stable product. Thus, the phenomenon of radioactive ingrowth that is observed for the natural decay chains is not observed; radioactivity associated with these tracers will decrease over time. Additionally, many of the tracers have relatively short half-lives (ex: 131I t1/2= 8.025 days) and will consequently decay to stable decay products in a short period of time, unlike the natural decay chains which will produce radioactive decay products for millennia. The greatest potential for lasting radioactive contamination during the injection stage is in the event the high pressure causes the well casing to fail. The frequency of casing failure in unconventional gas wells, albeit debatable, is more likely than in conventional wells (80). Estimates of casement failure rates are quite variable with rates suggested from 1-2% to as high as 6.3% (11, 81). If a casing failure were to occur, there is the potential for fluids from the well, containing NORM (from recycled fluids and interstitial fluids) or radioactive tracers, to leach into aquifers (82). Although this scenario is unlikely, there have been reports of signatures unique to the Marcellus Shale formation appearing in shallow domestic wells near hydraulic fracturing operations (83, 84). To our knowledge, no comprehensive studies have been performed to identify levels of NORM present in groundwater around drilling operations. Due to the natural occurrence of NORM in most groundwater the impacts of drilling operations will be difficult to assess (85). Without a well-controlled, longitudinal study that has pre- and post- drilling data, conclusions may be prone to confirmation bias. Flowback and Flaring After the well has been fractured, the pressure at the wellhead is lowered to allow gases and fluids to return to the surface. Initially, returned fluids, termed flowback, consist largely of the hydraulic fracturing fluids that were injected (11). Over time, the well will continue to release fluids, termed produced fluids. These fluids are typically much higher in total dissolved solids (TDS), salinity, and NORM (44, 46). Over time, a well releases increasingly complex fluids that may be enriched in Ra isotopes naturally present in the fractured formation. Although Ra isotopes may be selectively solubilized in flowback/produced fluids, over time, 228Ra-decay products such as 228Ac, 228Th, 220Rn, 212Pb, 212Bi, 208Tl and 226Ra-decay products such as 222Rn, 214Pb, 214Bi, 210Pb, and 210Po will ingrow (63). In addition to liquid wastes, natural gas wells produce large volumes of gaseous waste. This gaseous waste includes hydrogen sulfide, volatile organic compounds (VOCs), natural gas, and radioactive Rn gas (86). Flaring and/or venting are common and necessary practices at natural gas extraction sites, for safety, environmental, and economic reasons (87). Although the extent to which flares reduce the environmental impact of produced gases is debatable (88), it will have no effect on the radioactivity of Rn gas. Surprisingly little attention has been paid to the extent/impacts of Rn gas during the flaring stage, even though Rn is a well-known contaminant of natural gas streams (89–91). One article has suggested that increased 222Rn levels in natural gas extracted from shale will increase radioactivity concentrations in homes (from use of stoves 106 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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and space heaters) in New York State, resulting in an additional 1,182-30,448 lung cancers (92). More data on the levels of 222Rn in natural gas streams at the source and end-point are needed to validate this assessment. Very little is known about the levels Rn on drilling sites, though a recent report indicates that levels of 222Rn on Marcellus Shale drilling sites are in the range of ambient background 222Rn concentrations in the US (7-26 Bq/m3) (78). As studies are designed to address radiological exposures associated with 222Rn, both on drilling sites and downstream, careful consideration of 222Rn decay products is needed. The long-lived progeny of 222Rn, 210Pb and 210Po, can adsorb to dusts and accumulate into higher organisms (93–96).

Treatment The final stage of unconventional drilling is treatment of solid and liquid wastes. Little peer-reviewed information is available about the composition of NORM in wastes from the Marcellus Shale region and their potential to migrate into the environment (15). To date, reports on NORM associated with unconventional drilling have largely focused on three components of the radioactivity: gross alpha/beta levels (97), analysis of Ra levels (43, 44, 98–100), and gamma spectrometry (101). Gross alpha/beta levels are a simple screening technique for radioactivity in environmental samples (102, 103), but they do not indicate which radionuclides are present in the waste. Thus, it is not feasible to determine whether the level of radioactivity will increase, persist, or decrease over time without subsequent analyses. Analysis of Ra levels in flowback and produced fluids liquid waste from Marcellus Shale unconventional drilling has proven challenging, and can be underestimated (in some cases > 100 fold) due to matrix interferences (43). Traditional drinking water methods and other wet chemistry methods for Ra isotopes do not work on the complex brines from the oil and gas fields (43). Methods such as gamma spectroscopy or radon emanation are superior for these samples as they are less affected by matrix composition (43). However, analysis of Ra isotopes alone does not provide information on the total radioactivity, which can increase substantially for over 100 years resulting from the ingrowth of the radiogenic progeny (63). Gamma spectroscopy is used to measure select gamma-emitting radionuclides in the natural decay series (63, 101). In some cases, measurements of gamma-emitters can be used to infer radioactivity concentrations of radionuclides that are not gamma-emitters (example, gamma emissions from 228Ac can be used to infer 228Ra levels). However, due to partitioning events in the subsurface, analysts cannot assume all radionuclides will be in equilibrium (example, 228Ac levels cannot be used to infer levels of its decay product 228Th) (63, 85). Gamma spectrometry alone cannot fully characterize the levels of NORM present, particularly with respect to Ra decay products (228Th, 222Rn, 210Pb and 210Po). Without comprehensive analyses of NORM in these wastes (i.e. gamma spectrometry and alpha spectrometry), the levels of exposure will remain relatively unknown. Most environmental monitoring reports of Marcellus Shale waste have focused on 226Ra associated with liquid waste (i.e. flowback and produced fluids) 107 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

and dose rates from solid waste (i.e. bit cuttings and drill cuttings) (43, 44, 46, 63, 98, 104).

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Liquid Waste In the US, oil and gas operations are exempt from many federal environmental protection regulations, such as the Safe Drinking Water Act (the so-called “Halliburton Loophole”) (105). Further, the levels of NORM in oil and gas wastes are not regulated at the federal level, but rather at the state level (106). Thus, treatment options for liquid wastes differ from state-to-state due to a combination of regulations, economics, and local geology (107). The major treatment options in the US for liquid wastes from unconventional drilling are: (1) direct discharge (i.e. spraying on roads) (2) chemical treatment at wastewater treatment plants, (3) deep surface injection, and (4) recycling (77). The Marcellus Shale region provides an interesting case study on how state regulations can affect the handling of liquid wastes. In Pennsylvania in particular, radioactivity in liquid wastes has proven to be a controversial issue (15). Since unconventional gas exploration and production in the Marcellus Shale region began in 2003 (76), there was a rapid surge in drilling and waste generation across the region (107). In 2014, for example, over 8000 active wells generated an estimated 5 billion liters of flowback and produced fluids (107). Liquid wastes in Pennsylvania are largely disposed of at wastewater treatment plants as there are no suitable deep-well injection sites (107). This practice has resulted in cases of contaminated sediments downstream from these facilities (78, 98). Despite high profile publications on Ra contamination from untreated or undertreated flowback and produced fluids, a recent report from the State of Pennsylvania indicates that waste treatment facilities are still poorly equipped to remove Ra from unconventional drilling wastes (78). However, it is important to note that many drilling operators in the Marcellus Shale region are moving towards flowback recycling practices (70, 108). As liquid waste management continues to shift towards recycling, the volume of produced liquid waste containing Ra to be treated and disposed at the surface will decrease. Radium isotopes appear to be liberated from the Marcellus Shale and soluble in the liquid waste (44, 46, 63), which is consistent with historical observations of disequilibrium in oil and natural gas brines from conventional operations (109). Two major complications with handling these wastes are (1) the large volume of brines produced (>5 billion liters in 2014 in PA alone) (107), and (2) the high levels of dissolved solids and divalent cations (Sr, Ca, Ba) present in the liquids, which can interfere with treatment processes aimed at removing Ra (67). When wastewater treatment plants are not equipped to handle these high levels of divalent cations, flowback and produced fluids wastes may flow through the wastewater treatment plant untreated or undertreated (98, 110–112). Discharges of undertreated waste may result in the accumulation of these divalent cations in sediments of riparian environments (98). This was recently evidenced by a report, in which the investigators documented that levels of 226Ra and 228Ra in sediments immediately downstream of the Josephine Wastewater Treatment 108 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Facility in Pennsylvania, USA, were several orders of magnitude higher than background levels upstream of the facility (98). Due to the high levels of Ra isotopes, the plant operator now plans to dredge the contaminated sediments (113). Other waste operators in Pennsylvania have experienced similar challenges in removing Ra from complex hydraulic fracturing wastes (78, 114). In response to these challenges, several groups have suggested mixing in high-sulphate coal mine drainage as an approach to precipitate Ba and Ra isotopes as insoluble sulphate complexes from the liquid waste of the Marcellus Shale (115, 116).

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Solid Waste There are numerous methods available for the disposal and treatment of solid wastes generated in the drilling process, including biological and non-biological treatments (117). In some states, solid waste is disposed of in landfills, though in other states, like Oklahoma, bit cuttings and drilling muds are tilled into agricultural soils (77, 118). Given the mass of solid waste generated by unconventional drilling (up to 250,000 kg/well) (77), there is surprisingly little information available on their radioactivity content. Most readily available information available arises from newspaper reports of trucks turned away from landfills after tripping radiation alarms. For example, one truck carrying Marcellus Shale bit cuttings was turned away from a Pennsylvania landfill, because the radioactive emissions from the load exceeded the allowable radiation threshold. The dose rate from these bit cuttings was measured at 0.96 μS/hr, which exceeded the Pennsylvania threshold of 0.5 μS/hr (104, 119). In another case at the Meadowfill Landfill in West Virginia, a truck was turned away when bit cuttings measured 2.12 μS/hr, exceeding the allowable limit of 1.5 μS/hr (120). While these events of solid waste exceeding the allowable dose thresholds invariably raise criticism and concern from citizens, the risk of radiation exposure (including Rn) to the general public is likely minimal (78, 121). Although assessments of radioactivity dose rates are useful from a health physicist’s perspective, dose rates provide little information about the elemental and isotopic composition of these materials. Only recently has limited information about the composition (natU, 232Th, 228Ra, and 226Ra levels) of the bit cuttings become available from a report by the State of Pennsylvania (78). More detailed radiochemical assessments of the elemental and isotopic composition are critical to determine the equilibrium status, ingrowth potential, and likelihood for NORM to migrate into the surrounding environment.

Research Needs There are many important research questions concerning NORM that have recently surfaced as unconventional drilling expands around the world. Three unanswered questions in the context of environmental radiochemistry are: (1) the fate and transport of 226Ra decay products in freshwater environments, (2) the behavior and composition of NORM in solid waste from NORM-enriched shale 109 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

formations, and (3) regional impacts of 222Rn gas released from 226Ra containing wastes, flares, and natural gas streams.

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Fate and Transport of 226Ra-Decay Products in Aqueous Environments As mentioned earlier, Ra from unconventional drilling waste can enter riparian environments (98). This observation has raised numerous questions about the fate and transport of Ra and methods to remove it from complex liquid wastes produced by unconventional drilling (115, 116, 122); however little research has been performed on Ra decay products. Due to radioactive ingrowth processes, wastes that contain natural Ra isotopes (228Ra, 226Ra, 224Ra, and 223Ra) will generate Ra decay products. Importantly, because Ra decay products have different physicochemical properties than Ra, methods that are designed to remove Ra from liquid wastes will not necessarily remove Ra decay products. The three Ra decay products of greatest interest are: 222Rn, 210Pb, and 210Po, because these isotopes possess radiochemical (sufficiently long half-lives) and physicochemical (unique chemistry from the supporting 226Ra) properties that allow for partitioning in the environment and possible bioaccumulation in higher organisms (94, 95, 123). On-going studies in fresh waters in West Virginia by our laboratory indicate that Ra decay products have accumulated in sediments to a level nearly five times that of 226Ra (Figure 6) (124). The mechanism of 210Pb and 210Po enrichment in sediments is still under investigation. One possibility is that 226Ra is more soluble in this environmental system and is constantly removed from the system, but steady inputs of 210Pb and 210Po into the lake readily accumulate onto mineral surfaces in lake sediments. Currently, we are investigating the role of seasonal fluctuations in the observed disequilibrium. Alternatively, dissolved 222Rn may be transported in effluent discharge pipes as the result of 226Ra scale formation (125). A steady stream of 222Rn could result in the enrichment of 222Rn-decay products, including 210Pb and 210Po, in water columns and sediments of seasonally anoxic lakes (126, 127). Previous research indicates that excess 210Po (disequilibrium with 210Pb) is likely to occur in the summer in anoxic lake bottoms as Fe and Mn minerals are reduced to soluble phases (126). Further studies on 210Pb and 210Po levels are needed to elucidate their speciation, potential for migration, and exposure risks.

110 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 6. Anticipated fates for 226Ra and 226Ra decay products in fresh water environments. Behavior and Composition of NORM in Solid Waste To date, there have been no peer-reviewed scientific investigations on the radiochemistry of unconventional drilling solid waste. Numerous questions beckon, such as how redox sensitive elements (U, Fe, Mn, etc.) will behave when removed from depth, and how alteration of redox sensitive elements will affect the mobility of NORM. For example, as described earlier, U was trapped in shale formations in its reduced, immobile, +4 oxidation state. When brought to the surface, bit cuttings will be exposed to an oxidizing environment, which will likely result in the oxidization of U4+ to hexavalent UO22+ (Figure 7) (128). Once in the 6+ oxidation state, U may more readily leach off of bit cuttings into the surrounding environment (129). It is difficult to assess the extent and rate of U oxidation as well as the potential for U6+ to leach from bit cuttings without more data. Though, some lessons may be gleaned from the American West, where U mine tailings were stored along the banks of the Colorado River (130). Oxidized U6+ from these tailings traveled into ground water, prompting years of research and attempts to reduce the mobile U to the immobile, U4+ with bioremediation (131). In areas, such as Oklahoma, where bit cuttings and drilling muds are directly applied to fields, we expect a similar fate of U as described in mine tailings from CO. In other regions where bit cuttings are stored in landfills, such as the Marcellus Shale, we suspect that leachates will contain measurable quantities of U though the risk to the public is likely minimal (78). Non-radioactive, redox sensitive elements are also important to consider in assessing the fate and 111 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

transport of NORM. Further research is needed to investigate the potential for and 210Po to migrate through the environment. As an aside, measurements of 238U are sometimes performed by mass spectrometry. Yet, given the alpha recoil enrichment processes that we described above, 234U will likely not be in secular equilibrium with 238U. As a result, determining 238U activity by its mass and applying the assumption that 234U activity is equivalent could underestimate the true radioactivity attributed to U isotopes (85). Furthermore, activity ratios of 234U/238U may provide valuable information for predicting NORM migration at contaminated sites (132). Thus, we recommend that when possible, isotopic natU levels be measured by alpha spectrometry or another suitable method (63).

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222Rn, 210Pb,

Figure 7. Oxidation of bit cuttings and other solid wastes may mobilize U and other NORM into ground water and other water resources. (Adapted with permission from reference (63)). Potential Regional Impacts of 222Rn 226Ra

sources constantly produce 222Rn gas. Considering that liquid waste from the natural gas industry is known to contain enriched levels of 226Ra, very little attention has been given to 222Rn. Researchers have known that 222Rn is present in natural gas, though it is currently unclear what levels are present in shale gas and whether these levels pose a hazard (92, 133, 134). Although a recent report from the State of Pennsylvania indicates levels of 222Rn are low in commercial gas, the levels of 222Rn released during fugitive gas emissions and flaring of unwanted gases were not investigated (78). Since 222Rn is not combustible, flaring will not remove its radiologic hazards. Once delivered to the atmosphere, 222Rn will form decay products, which are known to fallout in particulates and in precipitation (Figure 8) (135, 136). The progeny of 222Rn, such as 210Pb and 210Po, could then 112 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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be taken up by plants (such as tobacco), accumulate in lake bottom sediments, and ultimately organisms in the region (126, 137). We suspect any increases in 222Rn levels and 222Rn products (210Pb and 210Po) will require well-controlled longitudinal studies, as many drilling operations occur in areas with relatively high levels of background 222Rn (138).

Figure 8. Flaring of unwanted gases may result in regional increases of product fallout. (Adapted with permission from reference (63)).

222Rn-decay

Conclusion NORM is a well-documented contaminant of conventional oil and natural gas equipment and wastes. Many of the challenges associated with NORM management in conventional wastes apply to the management of unconventional drilling wastes. The complexity and scale of wastes produced by unconventional drilling have proven difficult to handle in even the most developed of nations with decades of experience in natural gas production. When waste management protocols are inadequate, enriched levels of NORM from unconventional drilling 113 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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activities can enter the environment. Most attention to date with respect to NORM in unconventional drilling waste has focused on the risks of Ra isotopes entering aqueous environments. Given the natural ingrowth processes of radioactive decay products, wastes that are enriched in Ra isotopes will either contain Ra decay products or produce Ra decay products. Thus, studies on the fate and transport of NORM liberated by unconventional drilling operations should include Ra decay products. Similarly, studies of solid waste should include progenitors of Ra isotopes. NORM is comprised of multiple elements and isotopes of different physicochemical and radiochemical properties that play a role in environmental partitioning and any potential human exposure. Further studies are needed to characterize NORM solid, liquid, and gaseous wastes generated by unconventional drilling operations.

Addendum: Basic Properties of NORM Uranium Although uses of uranium (U, [Rn]5f36d17s2) date back to 79 CE, when the Romans used U to add yellow to ceramic glazes, the discovery is credited to a German chemist, Martin Heinrich Klaproth, in 1789 (62, 139). Klaproth dissolved pitchblende in nitric acid then neutralized the solution with NaOH and precipitated yellow sodium diuranate and concluded this was a new element. He later named the new element after Uranus, the primordial Greek god of sky, because of its yellow colour and the recent discovery of the planet Uranus eight years earlier (139). There are three naturally occurring isotopes of U, 238U (t1/2= 4.468x109 years, α), 235U (t1/2= 7.04x108 years, α), and 234U (t1/2= 2.455x105 years, α) (25, 140). The behavior of U in the environment is greatly dependent on the redox conditions. While in U6+ (as UO22+) is the most stable cation in oxidizing conditions, it is readily reduced to U4+ in anoxic conditions. In general, U forms strong inorganic and organic complexes, but the strength of the species depends on the oxidation state (26).

In the case of Marcellus Shale, the formation is rich in U due to the accumulating U6+-carbonate (UO2CO3) species from the ancient ocean (35, 141). Now, the conditions are very reducing, immobilizing U and reducing it to U4+, therefore, U will be recovered with the bit cuttings. Once U is exposed to ambient conditions, it will be oxidized to U6+ and will be soluble. Protactinium Protactinium (Pa, [Rn]5f26d17s2) was first isolated by William Crooks in 1900 when he dissolved uranyl nitrate in ether but he was unable to characterize it as a new element, so he named it uranium-X (142). In 1913, Fajans and Göhring fully characterized uranium-X as new element and named it brevium because of the short half-life of 234mPa (142). Finally in 1917, a German group (Hahn and Meitner) and 114 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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a British group (Soddy and Crankston) independently discovered another isotope of Pa with a longer half-life and named it proto-actinium (later changed by IUPAC to protactinium), because it was the progenitor of actinium (4). There are two naturally occurring radionuclides of Pa, 234Pa (t1/2= 6.7 hours, β-) and 231Pa (t1/2= 32,760 years, α) (26, 143). In general, Pa exists as a pentavalent cation and forms strong affinity for inorganic complexing ligands:

In the environment, Pa is known to readily hydrolyze to form insoluble colloidal species, but in the presence of a high concentration of strong inorganic ligands, Pa may remain soluble (26, 142). In the conditions such as the Marcellus Shale, it is likely that Pa will be largely insoluble due lack of strong complexing ligands (i.e. F- and SO42-), and would be potentially recoverable in the bit cuttings. Thorium Thorium (Th, [Rn] 6d27s2) was first documented in 1823 in Norway. Morten Thrane Esmark found a black mineral on the island of Løvøya and presented it to his father, mineralogist Jens Esmark, and he could not identify the sample (144). Jens Esmark sent the sample to a Swedish chemist, Jöns Jakob Berzelius, who in 1828, concluded it was a new element and named it after Thor, the Norse god of thunder (144). There are six naturally occurring isotopes of Th, 234Th (t1/2= 27.1 days, β-) 232Th (t1/2= 1.4x1010 years, α), 231Th (t1/2= 25.52 hours, β-), 230Th (t1/2= 75,400 years, α), 228Th (t1/2= 1.9116 years, α), and 227Th (t1/2= 18.68 days, α) (26, 145). Generally, Th exists as a tetravalent actinide and is redox inactive in the environment. Because Th4+ is the dominant species, Th remains largely insoluble and but its mobility is greatly controlled by the ability to form complexes with organic and inorganic ligands:

While Th remains insoluble, it can coordinate strongly with particles in the environment and be mobilized by their transportation (26). In the Marcellus shale, Th will remain insoluble and be recoverable with the bit cuttings. However, 228Th, originating from 228Ra, will grow into secular equilibrium in the recover fluids. Actinium Actinium (Ac, [Rn] 6d17s2) was discovered in 1899 by a French chemist, named André-Louis Debierne, when he isolated it from pitchblende residues of Marie and Pierre Curie radium extraction. The name originates from the Greek word aktis, meaning beam or light, because of the eerie blue glow of Cerenkov radiation emitted from actinium (146). There are two naturally occurring isotopes of Ac, 228Ac (t1/2= 6.15 h, β-) and 227Ac (t1/2= 21.1772 years, β-) (26). Chemically, Ac behaves as a trivalent cation similar to the lanthanide elements, remaining mostly insoluble and pH inactive (146). Within the conditions in the Marcellus Shale, Ac will remain largely insoluble and is expected to be associated with 115 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

solid/particulate phases. However, 228Ac, originating from secular equilibrium in the recovered fluids.

228Ra,

will grow into

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Radium Radium (Ra, [Rn]7s2) was first discovered by Marie and Pierre Currie in 1898 in the form of radium chloride by extraction from pitchblende (21). The name radium originates from the Latin word radius, meaning ray, referring to radium’s intense production of energy rays (147). There are three common naturally occurring isotopes. 224Ra (t1/2 = 3.66 d) and 228Ra (t1/2 = 5.76 y) are found in the 232Th decay series; 226Ra (t1/2 = 1599 y) is found in the 238U decay series. Ra is not redox sensitive and is found in the +2 oxidation state in nature (42). Owing to its highly basic behavior, Ra is not easily complexed. Ra does however form simple ionic salts. Radium sulphate and Ra carbonate are very insoluble, while Ra hydroxide, chloride, bromide, and nitrate are all soluble (42). Radium tends to precipitate (and coprecipitate) with all barium, most strontium, and most lead compounds as ionic salts. Due to the low sulphate concentrations in the Marcellus Shale, Ra isotopes are expected to remain soluble in interstitial fluids, flowback, and produced fluids. Radon Radon (Rn, [Xe]4f145d106s26p6) was discovered in 1900 by Dorn, who called it radium emanation (139). Yet, since 1923 the element has been known as radon. Each of the primordial decay series includes an isotope of Rn: 219Rn (t1/2 = 3.96 s, sometimes referred to as actinon) belongs to the actinium series, 220Rn (t1/2= 55.6 s, sometimes referred to as thoron) belongs to the thorium series, and 222Rn (t1/2= 3.8235 days, commonly referred to as simply as radon). Radon is the heaviest noble gas, and is thus relatively chemical inert. Rn is relatively soluble in water, though the effects of high saline environments may significantly alter its partitioning between various phases in the subsurface (55). In the subsurface Rn is expected in brines (supported and unsupported) (148), organic layers (149), and in natural gas streams (89). Although Rn is relatively soluble in aqueous solutions, when liquids containing Rn are exposed to the atmosphere (open system) Rn gas will partition into the air as predicted by Henry’s Law. Furthermore, solids containing 226Ra will produce 222Rn (150). Polonium Polonium (Po, [Xe]4f145d106s26p4) historically referred to as Radium F, was the first element discovered by Madame Marie Curie during her investigations of pitchblende (139). Polonium was named after Poland, the home country of Marie Curie. It is one of the rarest elements, with natural abundances of only 100 μg of 210Po per ton of uranium ores (151). Investigations of the speciation and chemistry of Po is difficult as all known isotopes and isomers are radioactive. Furthermore, analysis of its chemistry is complicated by its volatility—at temperatures over 100°C, Po is volatized, thus preventing the use of high temperature environmental 116 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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sample preparations (152). There are several naturally-occurring Po isotopes, most of which have extremely short half-lives: 218Po (t1/2 = 3.098 min), 216Po (t1/2 = 0.145 sec), 215Po (t1/2 = 1.781 x 10-3 sec), 214Po (t1/2 = 164.3 x 10-6 sec), 212Po (t1/2 = 0.299 x 10-6 sec), and 211Po (t1/2 = 0.516 sec). The longest-lived naturallyoccurring Po isotope is 210Po (t1/2 = 138.376 days). Po is theorized to form the -2, +2, +4, and +6 valence states (151), though the environmentally relevant valence states are likely +2 and +4 (153). Po is readily dissolved in dilute acids, but can be easily concentrated on manganese oxides or iron hydroxide surfaces even in complex samples. Interestingly, some investigators have discovered that only a portion of total Po is extracted by iron hydroxides, suggesting that multiple valence states and species of Po may coexist under certain conditions (61). Po is an elusive element that often behaves in unexpected ways; however, under the strong reducing conditions of shale formations it is expected that Po will be particle reactive and mostly associated with bit cuttings/drill cuttings. Importantly, Po isotopes will ingrow into phases that contain either supporting Ra or Rn isotopes. We believe the environmental transport mechanism and ultimate fate of 210Po (and its progenitor, 210Pb) liberated by unconventional drilling will be one of the most interesting and challenging research questions in the coming years. Bismuth Bismuth (Bi, [Xe] 4f14 5d10 6s2 6p3) was first discovered in the 15th century and identified as a distinct element by Potts and Bergmann in 1739 (154). The name bismuth originates from the German words, weisse masse, meaning white mass. For centuries, Bi was confused with Pb (139). There are several naturally-occurring radioactive isotopes including: 215Bi (t1/2 = 7.6 min), 214Bi (t1/2 = 19.9 min), 212Bi, (t1/2 = 60.55 min), 211Bi (t1/2 = 2.14 min), and 210Bi (t1/2 = 5.102 day). Until recently, 209Bi was thought to be the heaviest stable isotope; however, new evidence suggests that this isotope emits low-energy α-particles with an extremely long half-live (t1/2 = 1.9 x 1019 year) (155). Bi is most commonly found in the +3 and +5 oxidation states and tends to form insoluble complexes (64, 139). Given this tendency, Bi is expected to adsorb to particulate and mineral phases. In practice 214Bi and 212Bi are important gamma emitting isotopes for determining levels of supporting Ra isotopes (156). Lead Lead (Pb, [Xe] 4f14 5d10 6s2 6p2) has been in common use for thousands of years and is renowned for its toxicity (139). The word ‘lead’ has Anglo-Saxon roots, yet the abbreviation ‘Pb’ is derived from the Latin word plumbum. Radioactive Pb has numerous applications in radiochemistry, geology, and medicine. naturally-occurring radioisotopes of Pb include: 214Pb (t1/2 = 26.8 min), 212Pb (t1/2 = 10.64 hour), 211Pb (t1/2 = 36.1 min), and 210Pb (t1/2 = 22.2 year). The 238U, 235U, and 232Th decay series all decay to a stable Pb isotope (206Pb, 207Pb, and 208Pb, respectively). Pb exhibits two oxidation states in solutions, the +4 oxidation state, or more commonly the +2 state (157). Pb is insoluble when complexed with halides, sulphates, carbonates, phosphates, and sulphides, 117 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

but soluble when complexed with nitrates, nitrites, citrates or acetates (157). In the environment, Pb tends to be relatively immobile, thus making it a useful pollution indicator (158). 214Pb and 212Pb are important isotopes for determining gamma emissions of supporting Ra isotopes (156). Due to (1) the difficulty in measuring 210Pb in comparison to other gamma-emitting NORM, and (2) the natural ingrowth of 210Pb from 226Ra source, we believe the fate and transport of 210Pb associated with unconventional drilling wastes is one of the most interesting and challenging areas of environmental radiochemistry research.

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Thallium Thallium (Tl, [Xe] 4f14 5d10 6s2 6p1) was discovered independently by Lamy and Crookes in 1861 (159). The name thallium is derived from the Greek word thallos, meaning ‘green shoot’ in reference to the green light it emits in spectrometers (139). There are two relevant radioactive isotopes of Tl: 208Tl (t1/2 = 3.053 min) of the 232Th series and 207Tl (t1/2 = 4.77 min) of the 235U series. Thallium has two observationally stable isotopes; 203Tl and 205Tl. Tl is most commonly found in a +1 or +3 oxidation state as ionic salts. In the +1 state Tl behaves similarly to potassium (K), which in part explains its chemical toxicity. In reducing environments, Tl is expected in the +3 state, where it behaves similarly to aluminium (III, Al) (159). Tl is commonly soluble, even in the carbonate form, but can be precipitated as a +1 ion with hydrogen sulfide, potassium chromate, potassium iodide or thionalide. Co-precipitation of thallium (III) in small amounts is possible with iron (III) hydroxide. Given the low atomic abundances and short half-lives of 207Tl and 208Tl, their potential to partition likely plays a minimal role in the gross transport of NORM from unconventional drilling wastes through the environment. In practice, the reliable gamma emissions from 208Tl are important for monitoring 224Ra and associated progeny.

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88. Caulton, D. R.; Shepson, P. B.; Cambaliza, M. O. L.; McCabe, D.; Baum, E.; Stirm, B. H. Methane Destruction Efficiency of Natural Gas Flares Associated with Shale Formation Wells. Environ. Sci. Technol. 2014, 48, 9548–9554. 89. Raymond H. Johnson, J.; Bernhardt, D. E.; Nelson, N. S.; Harry W. Calley, J. Assessment of Potential Radiological Health Effects from Radon in Natural Gas; U.S. E.P.A. Publication EPA-520/1-73-004; U.S. Environmental Protection Agnecy, Office of Radiation Programs: Washington, DC, 1973. 90. Rowan, E. L.; Kraemer, T. Radon-222 Content of Natural gas samples from Upper and Middle Devonian sandstone and shale reservoirs in Pennsylvania: Preliminary data. Open-File Rep. Ser. (USGS) 2012, 1159, 6. 91. Burton, E. XLVIII. A radioactive gas from crade petroleum. London Edinburgh Dublin Philos. Mag. J. Sci. 1904, 8, 498–508. 92. Resnikoff, M. Radioactivity in Marcellus Shale: Challenge for Regulators and Water Treatment Plants; Report for Radioactive Waste Management Associates, Bellows Falls, VT, 2012; p 15. 93. Bacon, M. P.; Belastock, R. A.; Tecotzky, M.; Turekian, K. K.; Spencer, D. W. Lead-210 and Polonium-210 in Ocean Water Profiles of the Continental Shelf and Slope south of New England. Cont. Shelf Res. 1988, 8, 841–853. 94. Cherrier, J.; Burnett, W. C.; LaRock, P. A. Uptake of Polonium and Sulfur by Bacteria. Geomicrobiol. J. 1995, 13, 103–115. 95. Fisher, N. S.; Burns, K. A.; Cherry, R.; Heyraud, M. Accumulation and Cellular Distribution of 241Am, 210Po, and 210Pb in Two Marine Algae. Mar. Ecol.: Prog. Ser. 1983, 11, 233–237. 96. Heyraud, M.; Cherry, R. Correlation of 210Po and 210Pb Enrichments in the Sea-Surface Microlayer with Neuston Biomass. Cont. Shelf Res. 1983, 1, 283–293. 97. Schumacher, B.; Griggs, J.; Askren, D.; Litman, B.; Shannon, B.; Mehrhoff, M.; Nelson, A. W.; Schultz, M. K. Development of Rapid Radiochemical Method for Gross Alpha and Gross Beta Activity Concentration in Flowback and Produced Waters from Hydraulic Fracturing Operations In Development; EPA/600/R-14/107; U.S. Environmental Protection Agency, Office of Research and Developlment: Washington, DC, 2014. 98. Warner, N. R.; Christie, C. A.; Jackson, R. B.; Vengosh, A. Impacts of Shale Gas Wastewater Disposal on Water Quality in Western Pennsylvania. Environ. Sci. Technol. 2013, 47 (20), 11849–11857. 99. Zhang, T.; Bain, D.; Hammack, R.; Vidic, R. D. Analysis of Radium-226 in High Salinity Wastewater from Unconventional Gas Extraction by Inductively Coupled Plasma-Mass Spectrometry. Environ. Sci. Technol. 2015, 49, 2969–2976. 100. Ying, L.; O’Connor, F.; Stolz, J. F. Scintillation Gamma Spectrometer for Analysis of Hydraulic Fracturing Waste Products. J. Environ. Sci. Health, Part A: Toxic/Hazard. Subst. Environ. Eng. 2015, 50, 511–515. 101. Landsberger, S.; Brabec, C.; Canion, B.; Hashem, J.; Lu, C.; Millsap, D.; George, G. Determination of 226Ra, 228Ra and 210Pb in NORM Products from Oil and Gas Exploration: Problems in Activity Underestimation Due to the Presence of Metals and Self-Absorption of Photons. J. Environ. Radioact. 2013, 125, 23–26.

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102. Jobbágy, V.; Wätjen, U.; Meresova, J. Current Status of Gross Alpha/Beta Activity Analysis in Water Samples: A Short Overview of Methods. J. Radioanal. Nucl. Chem. 2010, 286, 393–399. 103. Semkow, T. M.; Parekh, P. P. Principles of Gross Alpha and Beta Radioactivity Detection in Water. Health Phys. 2001, 81, 567–574. 104. McMahon, J. Fracking Truck Sets Off Radiation Alarm at Landfill. Forbes, April 24, 2013. http://www.forbes.com/sites/jeffmcmahon/2013/04/24/ fracking-truck-sets-off-radiation-alarm-at-landfill/ (accessed February 24, 2015). 105. Hines, D. The “Halliburton Loophole”: Exemption of Hydraulic Fracturing Fluids from Regulation under the Federal Safe Drinking Water Act; Report for Institute for Energy and Environmental Research of Northeastern Pennsylvania Clearinghouse at Wilkes University, Wilkes-Barre, PA, 2012. 106. Zielinski, R. A.; Otton, J. K. Naturally Occurring Radioactive Materials (NORM) in Produced Water and Oil-Field Equipment: An Issue for Energy Industry; USGS Fact Sheet FS-142-99; U.S. Geologic Survey, U.S. Department of the Interior: Denver, CO, 1999. 107. Lutz, B. D.; Lewis, A. N.; Doyle, M. W. Generation, Transport, And Disposal of Wastewater Associated with Marcellus Shale Gas Development. Water Resour. Res. 2013, 49, 647–656. 108. Rahm, B. G.; Bates, J. T.; Bertoia, L. R.; Galford, A. E.; Yoxtheimer, D. A.; Riha, S. J. Wastewater Management and Marcellus Shale Gas Development: Trends, Drivers, and Planning Implications. J. Environ. Manage. 2013, 120, 105–113. 109. Rosholt, J. N., Natural radioactive disequilibrium of the uranium series. USGS Bulletin 1084-A; U.S. Geologic Survey, U.S. Government Printing Office: Washington, DC, 1959. 110. Haluszczak, L. O.; Rose, A. W.; Kump, L. R. Geochemical Evaluation of Flowback Brine from Marcellus Gas Wells in Pennsylvania, USA. Appl.Geochem. 2013, 28, 55–61. 111. Ferrar, K. J.; Michanowicz, D. R.; Christen, C. L.; Mulcahy, N.; Malone, S. L.; Sharma, R. K. Assessment of Effluent Contaminants from Three Facilities Discharging Marcellus Shale Wastewater to Surface Waters in Pennsylvania. Environ. Sci. Technol. 2013, 47, 3472–3481. 112. Volz, C. D.; Ferrar, K.; Michanowicz, D.; Christen, C.; Kearney, S.; Kelso, M.; Malone, S. Contaminant Characterization of Effluent from Pennsylvania Brine Treatment Inc., Josephine Facility Being Released into Blacklick Creek, Indiana County, Pennsylvania: Implications for Disposal of Oil and Gas Flowback Fluids from Brine Treatment Plants; EPA Hydraulic Fracturing Study Technical Workshop 3, Fate and Transport; Arlington, VA, March 28−29, 2011. 113. Hunt, S. Ohio EPA, Health Officials Dismiss Radioactive Threat from Fracking. The Columbus Dispatch, January 27, 2014. http:// www.dispatch.com/content/stories/local/2014/01/27/radioactive-threat.html (accessed February 24, 2015).

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114. Colaneri, K. Environmentalists Say Oil and Gas Waste Water Still Discharged into Allegheny River. StateImpact Pennsylvania, National Public Radio, July 19, 2013. 115. Kondash, A. J.; Warner, N. R.; Lahav, O.; Vengosh, A. Radium and Barium Removal through Blending Hydraulic Fracturing Fluids with Acid Mine Drainage. Environ. Sci. Technol. 2013, 48, 1334–1342. 116. Zhang, T.; Gregory, K.; Hammack, R. W.; Vidic, R. D. Co-Precipitation of Radium with Barium and Strontium Sulfate and Its Impact on the Fate of Radium during Treatment of Produced Water from Unconventional Gas Extraction. Environ. Sci. Technol. 2014, 48, 4596–4603. 117. Ball, A. S.; Stewart, R. J.; Schliephake, K. A Review of the Current Options for the Treatment and Safe Disposal of Drill Cuttings. Waste Manage. Res. 2012, 30, 457–473. 118. Penn, C.; Zhang, H. An Introduction to the Land Application of Drilling Mud In Oklahoma; Report WREC-102; Oklahoma State University Water Research and Extension Center: Stillwater, OK. 119. Allard, D. J. Marcellus Shale & TENORM. In Pennsylvania Emergency Management Agency Emergy Management Conference, Harrisburg, PA, September 24, 2011. 120. Hopey, D. West Virginia Won’t Accept Additional Drilling Waste Tainted With Radioactivity. Pittsburgh Post-Gazette, May 29, 2014 http://www.post-gazette.com/local/region/2014/05/29/West-Virginia-rejectsdrilling-waste-tainted-with-radioactivity/stories/201405290267 (accessed February 24, 2015). 121. Smith, K. P.; Arnish, J. J.; Williams, G. P.; Blunt, D. L. Assessment of the Disposal of Radioactive Petroleum Industry Waste in Nonhazardous Landfills Using Risk-Based Modeling. Environ. Sci. Technol. 2003, 37, 2060–2066. 122. He, C.; Zhang, T.; Vidic, R. D. Use of Abandoned Mine Drainage for the Development of Unconventional Gas Resources. Disruptive Sci. Technol. 2013, 1, 169–176. 123. Dlugosz-Lisiecka, M.; Wrobel, J. Use of Moss and Lichen Species to Identify 210Po Contaminated Regions. Environ. Sci.: Processes Impacts 2014, 16, 2729–2733. 124. Nelson, A. W.; Knight, A. W.; Eitrheim, E. S.; May, D.; Schultz, M. K. Unpublished work, University of Iowa, Iowa City, IA, 2015. 125. Field, R. W.; Fisher, E. L.; Valentine, R. L.; Kross, B. C. Radium-Bearing Pipe Scale Deposits: Implications for National Waterborne Radon Sampling Methods. Am. J. Public Health 1995, 85, 567–570. 126. Kim, G.; Kim, S.-J.; Harada, K.; Schultz, M. K.; Burnett, W. C. Enrichment of Excess 210Po in Anoxic Ponds. Environ. Sci. Technol. 2005, 39, 4894–4899. 127. Burnett,W. C.; Dimova, N.; Dulaiova, H.; Lane-Smith, D.; Parsa, B.; Szabo, Z. Measuring Thoron (220Rn) in Natural waters. In Environmental Radiochemical Analysis III; Warwick, P., Ed.; The Royal Society of Chemistry: Cambridge, 2007; pp 24−37. 128. Langmuir, D. Uranium Solution-Mineral Equilibria at Low Temperatures with Applications to Sedimentary Ore Deposits. Geochim. Cosmochim. Acta 1978, 42, 547–569.

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129. Mason, C. F. V.; Turney, W. R. J. R.; Thomson, B. M.; Lu, N.; Longmire, P. A.; Chisholm-Brause, C. J. Carbonate Leaching of Uranium from Contaminated Soils. Environ. Sci. Technol. 1997, 31, 2707–2711. 130. Final Site Observational Work Plan for the UMTRA Project Old Rifle Site; GJO-99-88-TAR; U.S. Department of Energy: Grand Junction, CO, 1999. 131. Anderson, R. T.; Vrionis, H. A.; Ortiz-Bernad, I.; Resch, C. T.; Long, P. E.; Dayvault, R.; Karp, K.; Marutzky, S.; Metzler, D. R.; Peacock, A. Stimulating the in Situ Activity of Geobacter Species to Remove Uranium from the Groundwater of a Uranium-Contaminated Aquifer. Appl. Environ. Microbiol. 2003, 69, 5884–5891. 132. Zielinski, R. A.; Chafin, D. T.; Banta, E. R.; Szabo, B. J. Use of 234U and 238U Isotopes to Evaluate Contamination of near-Surface Groundwater with Uranium-Mill Effluent: A Case Study in South-Central Colorado, U.S.A. Environ. Geol. 1997, 32, 124–136. 133. van der Heijde, H. B.; Beens, H.; de Monchy, A. R. The Occurrence of Radioactive Elements in Natural Gas. Ecotoxicol. Environ. Saf. 1977, 1, 49–87. 134. Wojcik, M. Long-Term Measurements of Rn and Short Lived Rn Daughter Concentrations in Natural Gas from Distribution Line. Health Phys. 1989, 57, 989–991. 135. Livesay, R. J.; Blessinger, C. S.; Guzzardo, T. F.; Hausladen, P. A. Rain-Induced Increase in Background Radiation Detected by Radiation Portal Monitors. J. Environ. Radioact. 2014, 137, 137–141. 136. Gaffney, J. S.; Orlandini, K. A.; Marley, N. A.; Popp, C. J. Measurements of 7Be and 210Pb in Rain, Snow, and Hail. J. Appl. Meteorol. 1994, 33, 869–873. 137. Persson, B. R. R.; Holm, E. Polonium-210 and Lead-210 in the Terrestrial Environment: a Historical Review. J. Environ. Radioact. 2011, 102, 420–429. 138. Map of Radon Zones, U.S. Environmental Protection Agency. http:// www.epa.gov/radon/zonemap.html (accessed February 24, 2015). 139. Emsley, J. Nature’s Building Blocks: An AZ Guide to the Elements, new ed.; Oxford University Press: Oxford, 2011. 140. Gindler, J. The Radiochemistry of Uranium; National Academies of Sciences Nuclear Science Series 3050; U.S. Atomic Energy Comission, U.S. Department of Commerce: Springfield, VA, 1962. 141. Wang, J. Natural Organic Matter and Its Implications in Uranium Mineralization. Geochem. 1984, 3, 260–271. 142. Myasoedov, B.; Kirby, H.; Tananaev, I. Protactinium. In The Chemistry of the Actinide and Transactinide Elements, 3rd ed.; Morss, L. Edelstein, N., Fuger, J., Eds.; Springer: Dordrecht, 2006; pp 161−252. 143. Kirby, H. The Radiochemistry of Protactinium; National Academies of Sciences Nuclear Science Series 3016; U.S. Atomic Energy Comission, U.S. Department of Commerce: Springfield, VA, 1959. 144. Wickleder, M.; Fourest, B.; Dorhout, P., Thorium. The Chemistry of the Actinide and Transactinide Elements, 3rd ed.; Morss, L. Edelstein, N., Fuger, J., Eds.; Springer: Dordrecht, 2006; pp 52−160.

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145. Hyde, E. The Radiochemistry of Thorium; National Academies of Sciences Nuclear Science Series 3004; U.S. Atomic Energy Comission, U.S. Department of Commerce: Springfield, VA, 1960. 146. Kirby, H.; Morss, L. Actinium. The Chemistry of the Actinide and Transactinide Elements, 3rd ed.; Morss, L. Edelstein, N., Fuger, J., Eds.; Springer: Dordrecht, 2006; pp 18−51. 147. Periodic Table: Radium. http://www.rsc.org/periodic-table/element/88/ radium (accessed February 24, 2015). 148. Mazor, E. Radon and Radium Content of Some Israeli Water Sources and a Hypothesis on Underground Reservoirs of Brines, Oils and Gases in the Rift Valley. Geochim. Cosmochim. Acta 1962, 26, 765–786. 149. Schubert, M.; Lehmann, K.; Paschke, A. Determination of Radon Partition Coefficients between Water and Organic Liquids and Their Utilization for the Assessment of Subsurface NAPL Contamination. Sci. Total Environ. 2007, 376, 306–316. 150. Walter, G. R.; Benke, R. R.; Pickett, D. A. Effect of Biogas Generation on Radon Emissions from Landfills Receiving Radium-Bearing Waste from Shale Gas Development. J. Air Waste Manage. Assoc. 2012, 62, 1040–1049. 151. Figgins, P. The Radiochemistry of Polonium; National Academies of Sciences Nuclear Science Series 3037; U.S. Atomic Energy Comission, U.S. Department of Commerce: Springfield, VA, 1961. 152. Matthews, K. M.; Kim, C.-K.; Martin, P. Determination of 210Po in Environmental Materials: A Review of Analytical Methodology. Appl. Radiat. Isot. 2007, 65, 267–279. 153. Ansoborlo, E.; Berard, P.; Den Auwer, C.; Leggett, R.; Menetrier, F.; Younes, A.; Montavon, G.; Moisy, P. Review of Chemical and Radiotoxicological Properties of Polonium for Internal Contamination Purposes. Chem. Res. Toxicol. 2012, 25, 1551–1564. 154. Sun, H.; Li, H.; Sadler, P. J. The Biological and Medicinal Chemistry of Bismuth. Chem. Ber. 1997, 130, 669–681. 155. de Marcillac, P.; Coron, N.; Dambier, G.; Leblanc, J.; Moalic, J.-P. Experimental Detection of α-Particles from the Radioactive Decay of Natural Bismuth. Nature 2003, 422, 876–878. 156. Moore, W. S. Radium Isotope Measurements Using Germanium Detectors. Nucl. Instrum. Methods Phys. Res. 1984, 223, 407–411. 157. Gibson, W. The Radiochemistry of Lead; National Academies of Sciences Nuclear Science Series 3040; U.S. Atomic Energy Comission, U.S. Department of Commerce: Springfield, VA, 1961. 158. Bränvall, M. L.; Bindler, R.; Emteryd, O.; Renberg, I. Four Thousand Years of Atmospheric Lead Pollution in Northern Europe: a Summary from Swedish Lake Sediments. J. Paleolimnol. 2001, 25, 421–435. 159. Chemistry of aluminium, gallium, indium, and thallium, Downs, A. J., Eds.; Chapman Hall: Glasgow, 1993.

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Chapter 5

Total Water Cycle Management for Hydraulic Fracturing in Shale Gas Production Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch005

Edwin Piñero* Senior Vice President for Sustainability and Public Affairs, Veolia North America, 200 East Randolph Street, Suite 7900, Chicago, Illinois 60601, United States *E-mail: [email protected]

As the number of shale gas fracturing operations increase, more water is being extracted from already strained water supplies. Disposal options for the higher TDS wastewater generated from both fracturing wells and producing wells are also becoming limited and less economical. Therefore, managing flowback and produced waters must recognize the unique situations in each region by maximizing the combination of technology, process, and management to get the best results that address those long term sustainability factors. Available treatment capacity will require a comprehensive water treatment strategy to address these challenges for future growth in the industry. The strategy must address any combination of: llimited alternatives to treat high TDS flowback and produced water; removal of free oil and grease; reducing overall waste volume; limited water re-use; and management of the entire water cycle. This paper discusses key steps in devising a treatment strategy.

Hydraulic fracturing is a topic that relatively recently has been in the forefront of the energy discussion. The significant growth of shale gas development as a source of energy, and advancement in approaches such as directional drilling, have prompted much discussion and action in terms of technology, operations, policy and regulation, and fundamental public debate. Interestingly however, this process of enhanced recovery of hydrocarbons from relatively tight formations is not new. Oil and gas production has used hydraulic fracturing and directional drilling for © 2015 American Chemical Society In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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decades. The resulting expansion of this recovery approach throughout the United States and elsewhere has raised public awareness and concern over the possible impact to water resources. There are many elements associated with shale gas production, including hydraulic fracturing, that have prompted discussion, and in many cases debate. This paper will focus on one element- the management of the water use cycle associated with hydraulic fracturing. As with many energy source development situations, dealing with water can be significant, and almost as important as the hydrocarbon resource itself. Even focusing on water, there are many aspects involved. It is important to distinguish water issues that are typical of any oil and gas operation, even if hydraulic fracturing is not involved, and even if shale gas itself is not involved. These include contaminant releases to surface water from well pad operations; sediment and erosion issues from site operations and related transportation (such as truck traffic). There are also water-related issues associated with the hydraulic fracturing process, but more a function of other activities. A good example of this is cross-contamination of aquifers during hydraulic fracturing, but not due to the hydraulic fracturing process itself, but due to poor well construction and/or poor understanding of the local geology. Herein we will focus on the water cycle focused on the water supply to serve as the hydraulic fracturing fluid medium, and management and treatment of the flowback water from the hydraulically fractured wells. Even within this relatively limited scope, we must deal with items such as: • • • • • • •

Availability of water to be used to prepare the fracturing fluids Transport logistics and costs of raw water and flowback water needing treatment Solid waste management of sludges resulting from treatment of flowback water Overall logistical issues such as remote and decentralized locations, storage restraints, limited in-place infrastructure (pipelines) Regulatory issues Ultimate disposal options for treated water Treatment options that are adaptable to variable conditions and settings

One must not look at this list as having single answers for each one. The truth about water cycle management is that all of these listed elements are very situationand location-specific. There is no single solution for the storage issue, for example. But on the positive side, these elements all lead to the need for cost-effective solutions that address the quantity and quality aspects of water related to hydraulic fracturing. It is important to realize the distinction between players in this process. Typically, the energy resource producer (the “oil company”) will manage the well site selection and drilling specifics, but contract others to actually do the hydraulic fracturing, and possibly yet another contractor to manage the water aspects. This paper is written from the perspective of the water management service provider. Water cycle management includes three basic phases: providing the water to be used for hydraulic fracturing; collection of resulting flowback water; and treatment and disposition of the flowback water. As a result, there are many 130 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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opportunities to take innovative approaches to improve and enhance hydraulic fracturing-related water cycle management. Although these steps can be addressed as separate activities, we contend that the more preferred approach is to look at the entire water cycle holistically and look for synergies between the steps. At each of these steps, there are quantity as well as quality issues. For quantity, the issue could be ensuring there is enough water to prepare the fracturing fluids, and proper procedures in place to handle the produced water coming from the operation. For quality, it is not only the more commonly discussed quality of flowback water quality, but also the quality if the incoming raw water. The quality of the raw water is important to control to ensure that the chemical mix ensures an effective fracturing fluid. For both quality and quantity, sustainable solutions must include environmental and resource considerations; as well as economic and quality of life aspects. In other words, sustainable solutions should include consideration of environmental, economic, and social aspects. This paper mentions both hydraulic fracturing fluid and flowback water. It is appropriate to make the distinction at this point. The fracturing fluid is the mixture used by the producer or hydraulic fracturing contractor to inject into the well to fracture the formation. This mixture is typically over 90% water, 9% sand (as a propant) and approximately 1% of a mixture of chemicals needed to effectively fracture the formation and hold it open for gas to flow, without adversely reacting with the formation itself. For the fracturing fluid, the water must be of suitable quality to not adversely interact with the hydraulic fracturing chemicals and additives, and of course there must be enough water. The amount of water needed to hydraulically fracture a well is widely variable, and can range from less than a million gallons, to over five million gallons per well. Availability of such raw water is a crucial element of the water cycle management. For the water management however, the more important fluid is the flowback water. Once the fracturing fluid is injected into the well, its character changes and the resulting flowback water is of different character. Flowback water is the encompassing term for the water that comes back from the well after the fracturing injection pressure is released, and the well begins to flow. Because of immediate mixing with formation water, the character, volume, and chemistry of the fracturing fluid changes. In terms of treating the water, it is the volume and quality of the flowback water that is the more important issue. Flowback water chemistry typically includes some of the hydraulic fracturing additives, but also inputs from the formation itself. These compounds include salts, metals, organic compounds, and in some cases, naturally occurring radioactive materials. It is possible that the hydraulic fracturing additives react with the formation chemistry to produce yet other compounds that must be addressed. Flowback volumes are highly variable in that many oil and gas producing formations also produce copious amounts of water. It is possible to recover millions of gallons more water as flowback water than were originally injected into the well. Understanding these aspects and nuances of flowback water from hydraulic fracturing operations lead to opportunities for preferred solutions. In regard to quality, one approach is to apply the “fit for use” concept. This means that water treatment quality targets should be a function of intended disposition. Traditional 131 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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approaches would treat to discharge permit quality levels, or to levels suitable for deep well injection. However, one way to reduce the cost and technical hurdles of treatment, and at the same time partially address the available quantity issue, is to treat the water to levels suitable for reuse. For operational purposes, Veolia defines three levels of treatment from which to choose in order to specify the optimal technology choice. Level I is minimal treatment, where the only treatment may involve physical treatment and total suspended solids removal. Depending on the reuse intent, such as for hydraulically fracturing another well, such treatment may be sufficient. However, if additional treatment is needed, one can go to Level II, which also includes specific ion removal. This level would be needed to ensure no adverse interaction between reused water chemistry and either fracturing fluid and/or formation water chemistry. The third and most involved and expensive level is Level III, which treats to discharge permit limits. Specific limits for Level III would be a function of the receiving water body, and would be reflected in any permits. Level III treatment typically may include thermal (evaporation and crystallization) for high total dissolved solids (TDS) levels; or membrane technology for lower TDS levels. The technology for such treatment levels exist. What leads to the best option takes into consideration the flowback volumes (total and rate) and site specific logistics. In other words, what are the local logistics. On the one extreme, examples exist in the Marcellus area of Pennsylvania where modular treatment units are necessary because of the isolated and decentralized nature of well locations. These treatment options are capable of rapid and simple mobilization/demobilization, but also able to handle high flow rates (over 10,000 barrels per day) and get levels suitable for water reuse. If cost effective transportation or storage of treated water for reuse is not practical or economical, these technologies can also treat water to Level III discharge limits. At the other extreme is an example from San Ardo, California where there is a high density of production, resulting in an opportunity to manage large volumes of water and for installation of more permanent infrastructure. The San Ardo case, although not directly involving fracturing water, does handle large amounts of formation water. San Ardo is also unique in that the treatment process not only effectively and sustainably treats the water, but also actually results in a net positive for the local water resource. First, some of the treated water from the formation is used to generate steam. The steam is used to inject into the formation to reduce the viscosity of the hydrocarbons to facilitate recovery. Rather than having to use freshwater from the local ecosystem, the steam demand is partially made up by reused formation water. Secondly, the excess treated water not used for steam is released into the local waterway. Because this is a relatively arid area with low flows, especially during drought, the treatment operation actually improves the local water balance. The San Ardo facility is able to provide 70,000 barrels of water per day for steam generation, and another 50,000 barrels per day as surface discharge. The water quality is so pure from the treatment process that it must be re-mineralized before surface discharge. One other attribute of this facility is that the recovered oily waste can be included with crude oil production of the local fields. 132 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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As we see from these cases, a total water cycle management approach allows for integrating quality and quantity aspects to come up with more effective and efficient solutions. We see from the examples that treating water from hydraulic fracturing operations is already very possible; yet processes and technologies continue to improve. At the core is the ability to reuse the treated water. If this treatment can be coupled with innovative approaches to deal with the logistical challenges, hydraulic fracturing process water management will not be a hindrance to shale gas development. Mobile treatment units, high flow rate treatment technologies, and larger geographic scale water management can offer solutions to the physical challenges posed by current hydraulic fracturing operations in less mature areas in regard to oil and gas production infrastructure. Having the ability to address the whole life cycle, and coordinate among production sites is the preferred solution. The next big leap will not be incremental improvements in how we handle each individual step of the cycle, but how we integrate it all together to choose the best treatment option for the situation at hand. Leveraging innovative options that support reuse provide both quality and quantity answers.

133 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Chapter 6

Analysis of Ions in Hydraulic Fracturing Wastewaters Using Ion Chromatography Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch006

C. A. Fisher*,1 and R. F. Jack2 1Thermo

Fisher Scientific, 1214 Oakmead Parkway, Sunnyvale, California 94085, United States 2Thermo Fisher Scientific, 490 Lakeside Dr., Sunnyvale, California 94085, United States *E-mail: [email protected]

The quantity of water required for hydraulic fracturing puts considerable stress on this often scarce resource. As a result, well operators are increasingly recycling wastewater for additional fracturing cycles. The ion content can be used to guide the treatment strategy and indicate adjustments needed to the mix of fracturing fluid additives to optimize recovery. Organic acids and inorganic anions modulate pH, induce corrosion, and can be precursors to disinfection by products. Cations are primarily indicative of the propensity for scale formation, which can be countered by additional treatment or an increase in anti-scaling agents. Ion chromatography (IC) is the primary technique for ion analysis and uses ion-exchange chromatography to separate ionic species, which are then detected by conductivity. A challenge of wastewater analysis is the high salt content, which is overcome by sample dilution. In flowback, chloride was the predominant anion, followed by bromide, with a steady increase in concentration as more fluid was recovered. There was a similar increase in cations with sodium dominating, followed by calcium, strontium, and magnesium. Produced water had a comparable pattern of relative ion concentrations. Significant variability resulted from analyzing samples from different locations, indicating that geology plays a prominent role in determining ionic content.

© 2015 American Chemical Society In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Introduction Hydraulic fracturing has been used for decades in the U.S., although it has increased considerably in the last decade spurring rapid growth in the extraction of oil and gas from shale deposits. This process consists of drilling a well vertically down several thousand feet (thousands of meters) to a layer of hydrocarbon-rich shale and then horizontally for a mile (1.6 km) or more. Fracturing fluid is then injected under high pressure through perforations in the horizontal well casing to fracture the adjacent shale, releasing the natural gas and oil trapped there. The liquid portion of hydraulic fracturing fluid is composed of approximately 99% water with the remainder consisting of chemical additives. Sand is added to this fluid as a proppant to keep open the cracks that are formed, thereby facilitating oil and gas recovery. To optimize recovery, additives, such as friction reducers and scale inhibitors (1), are tailored to the site’s geology and the chemical characteristics of the water used (2). Following the release of pressure, the fluid that returns to the surface is referred to as flowback water, which is then pumped into lined storage ponds or tanks prior to recycling or disposal. In Pennsylvania (the state with some of the most extensive hydraulic fracturing activity) an average of 10% of the fluid injected is recovered as flowback (3), although, in some cases, recovery is as low as 4%. One concern of this low recovery is the possibility of leakage from sites of injection into the aquifer. Despite this low recovery, it is unlikely that residual fracturing fluid will eventually migrate to and contaminate overlying groundwater (4). Once gas or oil appears, marking the start of production, the water recovered is referred to as produced. This water contains some residual fracturing fluid, but will consist primarily of water that was present within the shale layer prior to fracturing (formation water). While hydraulic fracturing wastewater can be disposed of by injection into disposal wells, this practice is expensive because water typically is transported to locations that are distant from the hydraulic fracturing site and there is evidence that deep well injection may cause earthquakes (5), raising public fears and opposition to this activity. To address these concerns, wastewaters are increasingly being desalinated and treated for reuse, with the additional benefit of a reduction in the demand for local water (6). At each hydraulic fracturing location, a comprehensive water management plan should be established to optimize usage and minimize the impact on local water quality (7, 8). There are several points within the water use cycle at which an assessment of water quality would be beneficial (Figure 1). Regular monitoring of the quality of ground/well water in the vicinity of the hydraulic fracturing site could act as an early warning if contamination occurs as a result of hydraulic fracturing activities and can provide some assurance to local residents of the safety of this water. Assessing local water quality prior to the start of any hydraulic fracturing activities will also provide a baseline to which any values obtained post-hydraulic fracturing can be compared. In addition to liquids, there are also solid (e.g. sediments) and gaseous samples that are produced at a hydraulic fracturing site, which require multiple instruments to provide a comprehensive analysis of constituents, measuring properties such as salinity, radioactivity, and hydrocarbon composition (Figure 2). 136 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 1. Water use cycle in hydraulic fracturing. (see color insert)

Figure 2. Hydraulic fracturing workflow monitoring. AAS, atomic absorption spectroscopy; ICP-OES, Inductively Coupled Plasma Optical Emission Spectroscopy; MS, Mass Spectrometry; HR, high resolution; IRMS, Isotope Ratio Mass Spectrometry; MC, multicollector; LC, liquid chromatography; MS/MS, tandem MS; CAD, charged aerosol detector; GC, Gas Chromatography; GM, Geiger-Müller; NaI, Sodium Iodide detector; TDS, total dissolved solids; DO, dissolved oxygen ; HF, hydraulic fracturing. 137 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Not only is it a best practice in support of responsible hydraulic fracturing, as noted above, but ongoing site monitoring can be mandated by local regulations. Such monitoring can include samples collected from the recovered liquids as they emerge from the well and any settling ponds or tanks used for wastewater storage, in addition to adjacent surface and ground waters. Natural gas (primarily methane, a greenhouse gas) can be inadvertently released at hydraulic fracturing sites and should be monitored to ensure minimal impact on the environment (9). In the event of an inadvertent wastewater spill, the concentration of metals, cations, anions, surfactants and the amount of radiation present can be used to draft an effective response plan to minimize impact on the surroundings. To track the origins of released wastewater the ratio of isotopes, such as 87Sr/86Sr (characteristic of geological formations) (10), or identification of specific surfactants (11) can be used as tracers. Another potential hazard to human health is radiation derived from naturally occurring radioactive material (NORM), which can be monitored by measuring 226Ra, a major NORM component and a proxy for this radioactivity (12). In addition to preparedness in the event of any accidental release during storage or transport, a comprehensive analysis of wastewater composition can be used to determine its suitability for immediate reuse in additional hydraulic fracturing events (adjusting the additive blend to optimize gas and oil recovery) or to devise an efficient treatment strategy prior to other beneficial uses (such as crop irrigation or road deicing) (13). Sediments and brines resulting from treatment can also be evaluated prior to disposal as part of a responsible management plan. This chapter will focus on those analytes that can be measured using IC, which include inorganic anions, cations, and organic acids. Ion Chromatography The primary analytical technique used to determine ionic species in solution is IC. In this technique, a sample is injected onto a column containing resin modified with ion exchange groups for which the ions in solution have varying affinities based on their physical properties (charge, shape, hydrophobicity, size) (Figure 3) (14). Eluent at either a steady (isocratic) or increasing (gradient) concentration displaces bound ions. Following separation, the eluent passes through a suppressor module in which the background conductance of the eluent is reduced, while the electrical conductance of the analyte ions is enhanced. The conductivity of the solution is then measured by a conductivity detector (CD) and plotted versus time to produce a chromatogram of the analytes present in the sample. The conductivity is directly proportional to the analyte concentration. A standard curve is created from the peak areas of a mix of ion standards at several concentrations that is then used to quantify the analytes present in a sample. Eluents can be prepared manually or, as shown in Figure 3, automatically using an eluent generation cartridge in which a specified concentration of eluent is produced by electrolysis of water. Immediately following this cartridge is a continuously regenerated trap column (CR-TC) that removes any ionic contaminants in the eluent stream. Additional IC innovations that have facilitated 138 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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analysis include: the development of 4 µm resin particles that deliver higher resolution than previously available particles (~7 µm) (15); higher pressure systems, which allow the use of faster flow rates for shorter run times; and Capillary IC, which scales down injection volumes, column size, and flow rates so that less sample and reagent are used and less waste is generated (16).

Figure 3. Overview of a Reagent-free Ion Chromatography system. CR-TC, continuously regenerated trap column. (see color insert)

IC with suppressed CD has several advantages (14): in contrast to methods that rely on UV/Vis detection, there is no need for a chromophore to be present on the molecule of interest nor is there interference due to absorption of matrix components in the UV/Vis spectrum; multiple analytes can be detected in a single run; sample preparation is typically minimal, requiring only filtration and dilution; the column chemistry chosen dictates what species are retained, allowing separation to be optimized for a specific set of analytes and elimination of other matrix components in the void volume; large disparities in analyte concentrations can be tolerated (e.g. 10,000:1 sodium:ammonium); relatively high salt samples can be directly injected due to the availability of high capacity columns; additional data can be collected with downstream detectors because CD is non-destructive. Some of the limitations of IC with CD include: only charged (ionic) molecules are directly detected. Post-column reactions in combination with UV/Vis detection can be used to extend the range of analytes detected although each of these reactions is for a single, specific analyte; runs range from 10–30 min, although shorter run times can be achieved if the conditions are altered to focus on a smaller subset of ions; because column separation is optimized for singly and doubly charged molecules, highly charged molecules (≥ 3) are tightly retained 139 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

under standard conditions resulting in long retention times. Reaction conditions or column chemistry can be modified to favor these species, but at the expense of less tightly bound ions; definitive analyte identification requires the use of an additional detection technology, such as mass spectrometry.

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Challenge of Wastewater Analysis Low analyte concentration measurements often push the limits of detection using IC, while at the other extreme, samples such as hydraulic fracturing wastewater, can have levels that exceed 150,000 mg/L (2). Such high concentrations necessitate loading less sample volume or diluting prior to injection to avoid exceeding column capacity and to ensure that the concentrations determined fall within the calibration range. The latter is particularly important when regulated methods are used, which typically prescribe a concentration range for each analyte. There are several ways to determine sample concentration and thus the need for dilution or otherwise reducing the amount of sample injected: • •

•

Manual conductivity measurement followed by dilution. This can be tedious, labor intensive, and prone to errors. Automation using chromatography data system software that allows samples to be run undiluted and then, if the peak height or area of analytes in the resultant chromatogram exceeds a predefined limit, the amount of sample injected is reduced before re-analysis by using 1) a partial loop injection, 2) a smaller sample injection loop, or 3) dilution using an autosampler (Figure 4). An advantage of this approach is that the analysis is analyte-specific since each will produce a characteristic peak. A disadvantage is that the dilution is performed post-run, which means that the column is subjected to high concentration samples that can diminish its life. An alternative approach, that saves column life by determining potential overloading before injection, is the use of in-line conductivity measurement. With this approach the sample conductivity is determined prior to injection and, if the conductivity measured exceeds a specified value, the sample is either automatically diluted or less of it is injected.

One of the consequences of sample dilution is that, as samples are diluted, the limits of quantification for the analytes of interest become higher. For all of the analytes discussed here, the levels measured are sufficiently high that any adverse effects of their presence can be adequately assessed.

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Figure 4. Software-enabled sample analysis options for determining need for sample dilution (17). (see color insert)

Ion Analysis Anions in Flowback Hydraulic fracturing flowback from the Marcellus shale (Pennsylvania) was obtained from barrels of wastewater that were successively recovered in 500 barrel batches from the first 5000 barrels. i.e. F1 = barrels 1-500, F10= barrels 4500-5000. For IC analysis, the eluent concentration was adjusted to optimize peak separation and then the linear calibration ranges were determined by measuring the peak responses to concentration using triplicate injections of calibration standards. Plotting peak area versus concentration demonstrated linearity for the concentration ranges used with coefficients of determination (r2) > 0.999. Samples were diluted as required so that the concentrations measured fell within the linear range. As exemplified by the chromatogram in Figure 5, chloride was the predominant anion present in all of the flowback aliquots analyzed (and at its highest concentration in this fraction (F10)), while bromide was the second most abundant at ~100-fold lower concentration. The bottom portion of this figure displays an expanded view of the upper chromatogram and shows that low levels of sulfate and the organic acids, acetate and formate, were also detected.

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Figure 5. Determination of inorganic anions and organic acids in hydraulic fracturing flowback (F10) (17).

Over time, as the hydraulic fracturing process continues, the anionic content of flowback solutions changes. As can be seen in Figures 6 and 7, chloride and bromide concentrations increased ~10-fold from the first to the second fraction and then, in subsequent fractions, showed a slower, but steady increase. The observed increase in ionic content suggests that the longer fracturing fluid is in contact with the shale layer, the more salt that is mobilized into the flowback and the closer the wastewater comes to having a composition that is virtually identical to that of produced water. i.e., essentially no residual fracturing fluid, with the constituents being dictated by the formation water and the mineral content of the specific shale formation. These elevated concentrations would increase the amount of processing required for water treatment. Conversely, the concentration of acetate decreased sharply and then remained at low levels from fraction two onwards. To address the possibility that the drop in acetate levels was due to a concomitant increase in chloride levels, which may have overloaded the column and reduced its ability to bind other analytes, acetate was added to 100-fold dilutions of fractions five and ten at a concentration 50% of that already present. The recovery of acetate was 114 and 103%, for fractions 5 and 10, respectively. If high chloride levels had decreased the binding of acetate to the column, a lower recovery would have been expected, particularly for fraction 10, which had the highest chloride concentration. Since this was not the case, the large drop in acetate measured indicates a decrease in the amount present in hydraulic fracturing flowback water samples after the first fraction. Organic acids, such as acetate and formate, are added to fracturing fluid to adjust the pH, which is maintained within a narrow range to ensure the effectiveness of fracturing fluid additives (2). In contrast to the other analytes quantified, the level of sulfate remained relatively constant, averaging 13 mg/L. 142 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Figure 6. Concentration of chloride in flowback (17).

Figure 7. Concentration of inorganic anions and organic acids in flowback (17). (see color insert) Anions in Produced Water Produced water was obtained from several locations within the U.S. and were diluted 50-, 200-, and 500-fold for the Texas (TX), California (CA), and North Dakota (ND) samples, respectively, to be within the calibration range and to ensure that the column was not overloaded (Figure 8). Note that the earlier elution times and differing peak order obtained for produced water when compared to flowback (Figure 5) was due to use of an isocratic method for the latter and gradient for the former. The gradient, which started at 15 mM KOH, was used to increase the separation of the earlier eluting organic acids, which facilitated peak integration, and was then increased to 29 mM to ensure that all peaks eluted in less than 12 minutes. Similar to the results for flowback, the predominant anion present in produced water was chloride, followed by bromide at ~200-fold lower 143 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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concentration, and then sulfate. Acetate and formate were present at less than 50 mg/L, while low, but detectable amounts of fluoride were only present in the TX sample.

Figure 8. Determination of anions in produced water (18). (see color insert) The anion concentrations in produced water varied considerably depending on its source with ND having the highest overall values, followed by CA, and then TX. Large differences are also evident when the produced water samples are compared to the ion concentrations that were obtained from Marcellus Shale flowback. For this comparison, fraction 10 was used because it had the highest ion concentrations for the majority of the anions quantified. Chloride was highest in ND, followed by the Marcellus Shale flowback, CA, and TX (Figure 9). It was anticipated that produced water samples would have considerably higher ion concentrations than flowback water because produced water contains a high proportion of formation brine (i.e. water naturally residing within the shale layer). In contrast, flowback can contain a significant amount of fracturing fluid, which is typically low in salts. Consistent with this expectation, sulfate was significantly higher in produced water compared to flowback. While the chloride concentration from the ND sample was almost twice as high as for the Marcellus Shale flowback, the chloride concentrations of the other produced water samples were much lower. The reason for this discrepancy is likely due to comparing flowback and produced water from different hydraulic fracturing locations. It 144 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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has been reported that total dissolved solids from different shale formations can vary by as much as an order of magnitude (19), with considerable variation being found even within shale formations (20). Unfortunately, a direct comparison of flowback and produced water from the same site was not possible due to the lack of appropriate samples. Another factor that can influence results is the initial quality of the water used in the fracturing fluid. Moderately salty (brackish) waters, such as recycled wastewater, are increasingly being used as a starting component of this fluid and, as a consequence, the resultant flowback would likely have significantly higher salt concentrations compared to that obtained if fresh water was used.

Figure 9. Comparison of anions in produced water and flowback (FB) (18). (see color insert) The high chloride concentration of the ND sample indicates that this water would need considerable treatment and/or dilution if it is to be used for additional hydraulic fracturing, whereas the TX water would require much less treatment. As with Marcellus shale flowback, the relatively high bromide concentration of the ND sample points to the need for monitoring of wastewater that is treated for surface water discharge, particularly if this water will be a source of drinking water production, due to the potential for formation of bromate (a regulated carcinogen) (21) during ozonation or by surface water exposure to sunlight. Cations in Flowback As was done for anion analysis, to prevent column overloading and ensure that the analyte concentrations were in their linear range, samples were diluted 100-fold prior to cation analysis. The predominant cation present in flowback was sodium, while calcium was the second most abundant at just under one third that concentration (Figure 10). These were followed in concentration by magnesium, strontium, and potassium. The lower portion of Figure 10 displays a zoomed in view of the chromatogram in the upper portion, which shows that the concentrations of barium, ammonium, and lithium were less than 250 mg/L. In contrast to the conditions used in figures 5 and 8 (4 and 2 mm i.d. columns, respectively), the data shown in Figure 10 was produced using a capillary setup 145 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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(0.5 mm i.d. columns). A capillary IC system uses considerably less water (~100-fold less) and, consequently, generates much less waste, while obtaining data using a sample injection of only 0.4 μL (compared to the 25 µL used with a 4 mm i.d. system).

Figure 10. Determination of cations in hydraulic fracturing flowback (Fraction 4) (22).

Consistent with the results obtained for anions, the concentration of the majority of cations increased approximately 10-fold from the first to the second fraction and then, in subsequent fractions, showed a slower, but steady increase (Figure 11). While most showed a gradual increase, barium had a more dramatic change, more than doubling (from 160 mg/L (F2) to 360 mg/L (F10)). If this wastewater is to be reused for additional hydraulic fracturing events, knowledge of the cations present can be used to optimize the fracturing fluid mixture. The propensity of cations, such as calcium, strontium, and barium to form scale would gradually occlude the cracks that are formed in the shale or build up in pipes used to transport hydraulic fracturing-derived fluids reducing the efficiency of oil or gas recovery. To minimize scale formation, the amount of anti-scaling additive used would need to be increased and/or additional dilution with fresh water would be required.

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Figure 11. Concentration of cations in hydraulic fracturing flowback fractions (22). (see color insert)

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Cations in Produced Water As with anion analysis, the TX and CA samples were diluted 50- and 200-fold, respectively, while the ND sample was diluted further from the 500-fold dilution to 1000-fold prior to analysis because the ammonium concentrations were higher than the linear range. Samples were analyzed using conditions as shown in Figure 10. Consistent with the trend in anion concentrations, the concentration of cations was highest in the ND sample with sodium being the most abundant, followed by calcium, potassium, ammonium, and magnesium (Figure 12). Low concentrations of strontium and lithium were measured, while barium was not detected. A similar concentration trend was observed for the CA and TX samples, with sodium the highest, followed by calcium and magnesium. There was more than ~2x higher concentration of sodium (the most abundant cation) in the produced water from ND than in the other samples, including the flowback. Marcellus flowback water had considerably higher concentrations of strontium and barium, comparable levels of lithium, magnesium, and calcium, and much lower amounts of ammonium and potassium when compared to the ND produced water sample. While strontium and barium were low or absent in produced water, the relatively high calcium concentrations in the ND sample make recycling more challenging due to its propensity to form scale. An additional concern for any ND produced water treatment plan is the relatively high concentration of ammonium (~3,500 mg/L), particularly if this water is to be treated and discharged to surface water. Ammonium can damage aquatic and terrestrial life directly, in addition to increasing the risk of the formation of toxic disinfection byproducts in drinking water utilities that may be downstream of any treatment discharge. Brine treatment facilities may not adequately remove ammonium as evidenced by the elevated levels (up to 100 mg/L) still present in the effluent from such facilities in Pennsylvania (23) suggesting that particular care should be taken when handling high ammonium wastewaters to minimize the environmental impact. As noted for anions, the differences in cation concentrations of samples obtained from different sites were likely due to the differing geology of the shale formations in which the hydraulic fracturing occurred.

Figure 12. Comparison of cation concentrations in produced water and flowback (18). (see color insert) 148 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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Conclusion The concentration of both high and low abundance ions in hydraulic fracturing flowback and produced water can be accurately determined using standard bore or capillary systems with dilutions performed either manually or automatically, with the option of software enabled pre- or post-run analysis. The most abundant anions were chloride, sulfate, and bromide, while sodium, calcium, magnesium, potassium, and ammonium were the most prevalent cations. There was significant variation in ion concentrations when produced and flowback wastewater were compared, although the bulk of the differences seen were attributed to sampling from different geologies. For both types of wastewater, planning treatment and reuse strategies should consider the high concentration of anions, such as chloride, and the scale-forming cations that will dictate the precise mix of additives needed for optimal oil and gas recovery. Additionally, if discharge to surface water occurs following treatment, the potential impact on downstream processes, such as the formation of bromate during drinking water purification, should be assessed.

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What Chemicals Are Used, FracFocus Chemical Disclosure Registry. http://fracfocus.org/chemical-use/what-chemicals-are-used (accessed March 14, 2015). Bomgardner, M. Cleaner Fracking. C&EN 2012, 90, 13–16. Vidic, R. D.; Brantley, S. L.; Vandenbossche, J. M.; Yoxtheimer, D.; Abad, J. D. Impact of Shale Gas Development on Regional Water Quality. Science 2013, 340, 1235009. Engelder, T.; Cathles, L. M.; Bryndzia, L. T. The Fate of Residual Treatment Water in Gas Shale. J. Unconv. Oil Gas Res. 2014, 7, 33–48. Rubinstein, J. L.; Ellsworth, W. L.; McGarr, A.; Benz, H. M. The 2001-Present Induced Earthquake Sequence in the Raton Basin of Northern New Mexico and Southern Colorado. Bull. Seismol. Soc. Am. 2014, 104, 2162–2181. Mauter, M. S.; Alvarez, P. J.; Burton, A.; Cafaro, D. C.; Chen, W.; Gregory, K. B.; Jiang, G.; Li, Q.; Pittock, J.; Reible, D.; Schnoor, J. L. Regional Variation in Water-related Impacts of Shale Gas Development and Implications for Emerging International Plays. Environ. Sci. Technol. 2014, 48, 8298–8306. Jiang, M.; Hendrickson, C. T.; VanBriesen, J. M. Life Cycle Water Consumption and Wastewater Generation Impacts of a Marcellus Shale Gas Well. Environ. Sci. Technol. 2014, 48, 1911–1920. Rahm, B. G.; Riha, S. J. Evolving Shale Gas Management: Water Resource Risks, Impacts, and Lessons Learned. Environ. Sci. Process Impacts. 2014, 16, 1400–1412. Teasdale, C. J.; Hall, J. A.; Martin, J. P.; Manning, D. A. Ground Gas Monitoring: Implications for Hydraulic Fracturing and CO2 Storage. Environ. Sci. Technol. 2014, 48, 13610–13616. 149 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

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10. Kohl, C. A.; Capo, R. C.; Stewart, B. W.; Wall, A. J.; Schroeder, K. T.; Hammack, R. W.; Guthrie, G. D. Strontium Isotopes Test Long-term Zonal Isolation of Injected and Marcellus Formation Water After Hydraulic Fracturing. Environ. Sci. Technol. 2014, 48, 9867–9873. 11. Thurman, E. M.; Ferrer, I.; Blotevogel, J.; Borch, T. Analysis of Hydraulic Fracturing Flowback and Produced Waters Using Accurate Mass: Identification of Ethoxylated Surfactants. Anal. Chem. 2014, 86, 9653–9661. 12. Zhang, T.; Bain, D.; Hammack, R.; Vidic, R. D. Analysis of Radium-226 in High Salinity Wastewater From Unconventional Gas Extraction by Inductively Coupled Plasma-Mass Spectrometry. Environ. Sci. Technol. 2015, 49, 2969–2976. 13. Lester, Y.; Ferrer, I.; Thurman, E.; Sitterley, K.; Korak, J.; Aiken, G.; Linden, K. Characterization of Hydraulic Fracturing Flowback Water in Colorado: Implications for Water Treatment. Sci. Total Environ. 2015, 512–513, 637–644. 14. Weiss, J. Handbook of Ion Chromatography, 3rd ed.; Wiley-VCH: Weinheim, Germany, 2004; Vol. 1. 15. Benefits of Using 4 μm Particle-Size Columns; White Paper 7063; Thermo Fisher Scientific: Sunnyvale, CA, 2013. 16. What is Capillary Ion Chromatography?; White Paper 70552; Thermo Fisher Scientific: Sunnyvale, CA, 2013. 17. Determination of Anions in Fracking Flowback Water From the Marcellus Shale Using Automated Dilution and Ion Chromatography; Technical Note 139, TN70773_E; Thermo Fisher Scientific: Sunnyvale, CA, 2013. 18. Determination of Anions and Cations in Produced Water from Hydraulic Fracturing; Application Note 1105, AN71255_E; Thermo Fisher Scientific: Sunnyvale, CA, 2014. 19. Barbot, E.; Vidic, N. S.; Gregory, K. B.; Vidic, R. D. Spatial and Temporal Correlation of Water Quality Parameters of Produced Waters from Devonianage Shale Following Hydraulic Fracturing. Environ. Sci. Technol. 2013, 47, 2562–2569. 20. Vengosh, A.; Jackson, R. B.; Warner, N.; Darrah, T. H.; Kondash, A. A Critical Review of the Risks to Water Resources from Unconventional Shale Gas Development and Hydraulic Fracturing in the United States. Environ. Sci. Technol. 2014, 48, 8334–8348. 21. Drinking Water Contaminants, U.S. Environmental Protection Agency. http:/ /water.epa.gov/drink/contaminants/ (accessed March 14, 2015). 22. Determination of Cations in Hydraulic Fracturing Flowback Water From the Marcellus Shale; Thermo Scientific Application Note 1094, AN71085_E; Thermo Fisher Scientific: Sunnyvale, CA, 2014. 23. Harkness, J. S; Dwyer, G. S.; Warner, N. R.; Parker, K. M.; Mitch, W. A.; Vengosh, A. Iodide, Bromide, and Ammonium in Hydraulic Fracturing and Oil and Gas Wastewaters: Environmental Implications. Environ. Sci. Technol. 2015, 49, 1955–1963.

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Chapter 7

Emerging Environmental Impacts of Unconventional Oil Development in the Bakken Formation in the Williston Basin of Western North Dakota Venkataramana Gadhamshetty,*,1 Namita Shrestha,1 Govinda Chilkoor,1 and Jejal Reddy Bathi2 1Civil

and Environmental Engineering, South Dakota School of Mines and Technology, 501 E. St. Joseph Street, Rapid City, South Dakota 57701, United States 2Global Systems International, LLC, 1114 Carriage Park Dr., Chattanooga, Tennessee 37421, United States *E-mail: [email protected]. Tel: +1-605-394-1997.

The Devonian and Mississippian Bakken formation in the Williston basin of western North Dakota (ND) contains the largest known source of unconventional oil in the United States (U.S.). Advanced drilling and fracturing technologies have enabled exponential increase in oil production from previously inaccessible (low-permeability) shale formations in the Bakken formation. The state of ND now ranks as a second largest oil producing state in the U.S. However, the abrupt increase in unconventional oil production and associated economic benefits may bring long-term negative environmental impacts. There is a dire need to engage both the public and research scientists with the emerging environmental impacts of oil development. This chapter provides a critical summary of the potential impacts of the Bakken oil development on the diverse subdomains of the environment.

© 2015 American Chemical Society In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch007

1. Introduction The recent “oil boom” has transformed the U.S. into one of the largest oil producers in the world. The crude oil is typically classified as conventional, transitional, and unconventional oil. The conventional oil that dominated the twentieth century is characterized with light (i.e., low molecular weight) oil that flows easily, and can be extracted with a typical well bore using primary, secondary, and tertiary methods. Transitional oil is similar to conventional oil, but is struck sin remote and impermeable sites including ultra-deep wells; sandstones; carbonates deep below the ocean floor; and tight plays (e.g. Bakken Shale). Its extraction requires unconventional techniques including multi-stage hydraulic fracturing, horizontal drilling, external heating and dilution with chemical solvents. Unconventional oil is characterized by high viscosity and high sulfur content; typical examples include heavy oil from oil sand (bitumen) and oil shale (kerogen). Unconventional oil requires huge energy for its extraction, processing and refining operations (1). In 2000, the United States Geological Survey (USGS) provided the first quantifiable assessment on the world’s crude oil resources (2). In the same year, the Energy Information Administration (EIA) has posed the following bold question: “When will the world physically run out of crude oil?” The EIA has speculated that the answer depends upon the technological advancements in the fields of renewable energy-sources (e.g. fuel cells) and unconventional oil sources (e.g. tar sands). However, the Colorado River Commission believed that the world’s petroleum reserves will deplete by the year 2102 (3). In the recent times, the unconventional drilling (a combination of horizontal drilling and hydraulic fracturing (HF)) has changed the oil landscape in the U.S by allowing the petroleum companies to access oil from the most remote and tight oil bearing formations. The U.S. sits on the brink of an oil boom due to a sudden increase in the oil production during the past decade. For example, oil production in the year 2008 was 7.5 million barrels per day (bbl/d) and increased to 11 million bbl/d by 2013 (4). The new trend in the oil production is expected to continue for coming several years, primarily due to the ability of oil companies to fracture deep pre-salt fields, tighter shales, and remote geographical sites (5). The transitional oil is currently being mined from Bakken (ND, Montana (MT), Saskatchewan, and Manitoba), Eagle Ford (Barnett) Permian basin (Texas and New Mexico), Cardium (Alberta), Miocene (Monterey), Antelope (California), Mowry-Niobrara (Wyoming and Colorado), Penn Shale (Oklahoma), Exshaw MT), Utica (Colorado, Wyoming, and New Mexico) with additional shales being explored in New York, Maine, Mississippi, Utah, and Alaska’s North Slope and Cook Inlet (1). This chapter will focus on the unconventional oil development, and the associated environmental impacts, in the Bakken at the Williston basin of western ND.

152 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch007

1.1. Introduction to Bakken Shale A 2013 survey by the USGS has identified nearly 7.4 billion barrels of recoverable oil in the Bakken Formation and the Three Forks formation in the Williston basin. The use of horizontal drilling and multi-stage HF technologies has enabled the increase in the oil production from the Williston basin. The majority of this oil occurs in the state of ND. There are currently 12,000 active oil wells in the Bakken Play (6). ND is now ranked as the second largest crude oil-producing state in the nation (7). The Williston basin is a circular basin that extends into the states of ND, MT and South Dakota (SD) and the Canadian provinces of Manitoba and Saskatchewan; this basin houses the Devonian Three Forks Formations and the Devonian and Mississippian Bakken Formations (red line, Figure 1). The Bakken Total Petroleum System (TPS) includes the strata from the Devonian Three Forks Formation, Bakken Formation, and the lower part of the Mississippian Lodgepole Formation that may contain Bakken-sourced oil (Blue line, Figure 1) (8).

Figure 1. Williston basin province, Bakken total petroleum system (TPS). Adapted with permission from reference (8). Copyright 2013 U.S. Geological Survey. 153 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch007

The Devonian and Mississippian Bakken Formation include the Pronghorn Member, lower shale member, middle member, and upper shale member (9). The upper and lower shale members are the primary source rocks for the Bakken TPS (9). As mentioned earlier, the shale members are present in parts of MT and ND and extend into the Canadian provinces of Saskatchewan and Manitoba. Approximately 450 million barrels of oil (MMBO) have been produced from the Bakken and Three Forks Formations in the United States since the 2008 assessment of the Bakken Formation (9). In the last decade, the Bakken experienced an overwhelming increase in the oil production, 150 thousand bbl/d in 2007 to 1350 thousand bbl/d in 2015 (10).

2. Hydraulic Fracturing The hunt for oil resources results in oil drilling closer to human populations (11). Oil companies use HF techniques to extract oil from formations. The pressurized fluid is injected into well bores to induce fractures, expand existing fractures, carry ‘proppants’ into fractures, and finally promote the flow of oil to the surface. The drillers in the Bakken found water-supplemented fluids (e.g. drilling mud or polymer) to be advantageous due to its effectiveness to: i) stimulate fractures, ii) send proppants into fractures, iii) pull back the excess proppants after stimulating the fractures, iv) offer low friction, v) suspend the proppants and vi) revert back to the low-viscosity fluid at end of the fracturing process. The HF fluids are supplemented with a range of chemicals (12) to promote the fracturing process in the Bakken (Table 1).

Table 1. Typical chemicals used to fracture formations in the Bakken. Reproduced with permission from reference (12). Copyright 2015 U.S. EPA. Addititive

Example

Purpose

Buffer

Sodium hydroxide,Potassium hydroxide

Adjust the pH of the base fluid

Biocide

Ammonium chloride, TetrakisHydroxymethylPhosphonium

Reduce microbial growth

Breaker Catalyst

Sodium Chloride

Degrade viscosity Holds open fracture to allow oil and gas to flow to well

Proppant Crosslink Agent

Hydrotreated Light, Ethylene Glycol, Potassium Metaborate

Crosslink Enhancer Surfactant

Delayed crosslinker for the gelling agent Non-delayed crosslinker for the gelling agent

Isopropanol, Naphthalene, Ethanol

Aids in recovery of water used during frac Continued on next page.

154 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch007

Table 1. (Continued). Typical chemicals used to fracture formations in the Bakken. Addititive

Example

Purpose

Base Fluid

water

Creates fractures and carries proppant, also can be present in some additives

Acid / Solvent

Hydrochloric Acid, Muriatic acid

Minimize mud build-up; dissolve minerals; initiates cracks in rock matrix

Clay Stabilizer

Potassium chloride, Tetramethyl ammonium chloride

Prevent clay particles from migrating in water-sensitive formations. Prevents precipitation of iron oxides during acid treatment

Organic Acid

Friction Reducer

Polyacrylamides, petroleum distillate

Allows fracture fluid to move down the wellbore with the least amount of resistance

Liquid Gel Concentrate

Guar Gum

Gelling agent for developing viscosity

Corrosion Inhibitor

Methanol

Prevents acid from causing damage to the wellbore and pumping equipment

The composition of the fracturing fluid is often maintained as a trade secret by oil companies. The drillers use a custom recipe to obtain a suite of fracturing chemicals to match hydro-geochemical characteristics of the shale play and the HF method. The HF chemicals should ultimately improve the oil flow through the fractures, and minimize the volume of fracturing fluid. In the Bakken, the operators use a series of “swell packers” along a liner that is inserted in a freshlydrilled horizontal well (11). Special fluids are injected to swell the packers in order to isolate the selected portions of horizontal wells. The nature of the environmental problems at fracturing sites depend upon the HF methods and the chemical and physical characteristics of HF fluids. In a hypothetical example, a potential leak in the flowback water transportation system (e.g. during the transportation from the oil fields to Class II injection wells) can contaminate the adjacent water sources and agricultural fields. There is increasing public concern about environmental impacts due to abrupt oil development in ND (13). A majority of these issues have been highlighted in newspaper articles (14, 15). Based on publicly available information, this article provides a critical summary of the environmental concerns related to fracturing in the Bakken formation in the Williston basin of western ND. This chapter will be organized under the following categories of environmental impacts: water stress and water contamination; oil spills; methane stranding – open flare of natural gas; and air pollution. 155 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch007

3. Sources, Processes, and Hazards at Different Stages of Unconventional Oil Development Table 2 provides a summary of typical events relevant to oil extraction with horizontal drilling and HF. Each event has the potential to contaminate ground water, surface water, and air. For instance, heavy equipment for well pad construction can cause diesel emissions, noise and vibrations, and oil spills. The drilling and construction operations can release air pollutants related to drilling mud, rubber-based oil, synthetic oil, aluminum tristearate, choline chloride, aromatic and aliphatic hydrocarbons. The contaminants in the drilling muds (boric acid, borate salts, rubber-based oil, synthetic oil, aromatic and aliphatic petroleum hydrocarbons and inorganic chemicals; barium, strontium, bromine, heavy metals, salts and NORM (naturally occurring radioactive materials)) threatens ground water and surface water (16).

4. Impacts on Water Resources 4.1. Water Stress The HF puts immense stress on surface and groundwater sources, especially in the water-stressed regions of the U.S. For instance, during January 2011 to May 2013, the total water consumption for HF operations in six states (TX, PA, OK, AR, CO, and ND) exceeded 97 billion gallons of water (17) at the rate of a million gallon of fresh water per hydraulically fractured well (18). According to a recent report (17), nearly 50% of the unconventional oil wells that were hydraulically fractured since 2011 occur in regions with high or extremely high water stress; further, 55% of these wells are in regions experiencing droughts. The ‘region with extremely high water stress’ is defined as a region that allocated 80% of the available surface and groundwater for municipal, industrial, and agricultural uses (17). It can be speculated that water stress will be low in arid regions such as ND due to low population density and non-water-intensive agricultural practices. However, it is instructive to assess and evaluate the water-usage trends in an emerging oil play such as the Bakken. The water-usage-per-well in the Bakken play is typically higher than other shale oil-producing regions. Water consumption for horizontal oil wells in ND is at least two orders of magnitude higher than that for vertical wells in SD. Table 3 provides a comparison between the number of rigs, oil wells, and associated water consumption between the states of SD and ND (19).

156 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Oil drilling event

Ground water pollution

Surface water pollution

Air pollution

Safety Hazards

Nonchemical hazards

Sources

Process

Large trucks

All

Diesel emissions

Spill and accidents

Noise, vibration

Heavy equipment

Well pad construction, drilling and well abandonment

Diesel emissions

Spill and accidents

Noise, vibration

Dust

Well pad construction, well abandonment

Diesel emissions including particulate matter

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Table 2. Sources, processes, and hazards associated with oil exploration. Reproduced with permission from reference (16). Copyright 2014 American Chemical Society.

Drilling mud

Drilling

Drilling muds, e.g., boric acid, borate salts, rubber-based oil, synthetic oil

Fracturing fluid

Hydraulic fracturing, flowback

Fracturing fluids, e.g., lauryl sulfate, guar gum

Drilling muds, e.g., boric acid, borate salts, rubber-based oil, synthetic oil

Drilling Muds, Volatile, e.g., rubber-based oil, synthetic oil, aluminum tristearate, choline chloride

Fracturing fluids, e.g., lauryl sulfate, guar gum

silicaFracturing fluids, volatile: e.g., glutaraldehyde, ethylene glycol, methanol,, petroleum distillate

Spills

Continued on next page.

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Table 2. (Continued). Sources, processes, and hazards associated with oil exploration. Oil drilling event Sources

Process

Generators

Drilling, hydraulic fracturing

Produced water

Drilling cuttings

Ground water pollution

Surface water pollution

Air pollution

Safety Hazards

Diesel emissions

Drilling and construction, flowback

Drilling muds, e.g., boric acid, borate salts, rubber-based oil, synthetic oil,aromatic and aliphatic petroleum hydrocarbonsinorganic chemicals; barium, strontium, bromine, heavy metals, salts and NORM (naturally occurring radioactive materials)

Drilling muds, e.g., boric acid, borate salts, rubber-based oil, synthetic oil,aromatic and aliphatic petroleum hydrocarbonsinorganic chemicals; barium, strontium, bromine, heavy metals, salts and NORM

Drilling Muds, Volatile, e.g., rubber-based oil, synthetic oil, aluminum tristearate, choline chloridearomatic and aliphatic petroleum hydrocarbons

Drilling and construction

Drilling muds, e.g., boric acid, borate salts, rubber-based oil, synthetic oil,aromatic and aliphatic petroleum hydrocarbonsinorganic chemicals; barium, strontium, bromine, heavy metals, salts and NORM

Drilling muds, e.g., boric acid, borate salts, rubber-based oil, synthetic oil,aromatic and aliphatic petroleum hydrocarbonsinorganic chemicals; barium, strontium, bromine, heavy metals, salts and NORM

Diesel emissions, including particulate matterdrilling Muds, Volatile, e.g., rubber-based oil, synthetic oil, aluminum tristearate, choline chloride aromatic and aliphatic petroleum hydrocarbons

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Nonchemical hazards

Noise

Spills

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Oil drilling event Sources

Ground water pollution

Surface water pollution

Air pollution

Fracturing fluids, volatile: e.g., glutaraldehyde, ethylene glycol, methanol,, petroleum distillatearomatic and aliphatic petroleum hydrocarbons inorganic chemicals; barium, strontium, bromine, heavy metals, salts and NORM

Fracturing fluids, volatile: e.g., glutaraldehyde, ethylene glycol, methanol,, petroleum distillatearomatic and aliphatic petroleum hydrocarbons inorganic chemicals; barium, strontium, bromine, heavy metals, salts and NORM

Fracturing fluids, volatile: e.g., glutaraldehyde, ethylene glycol, methanol,, petroleum distillatearomatic and aliphatic petroleum hydrocarbons

Safety Hazards

Nonchemical hazards

Process

Flowback water

Flowback

Deep injection

Flowback

Gas venting

Drilling, flowback, production

Methanehydrogen sulfidearomatic and aliphatic petroleum hydrocarbons

Gas flaring

Drilling, flowback production

Carbon dioxidenitrogen oxides

Pigging

Production

Methanearomatic and aliphatic petroleum hydrocarbons

Seismic activity Accidents

Noise

Accidents Continued on next page.

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Oil drilling event

Ground water pollution

Surface water pollution

Air pollution

Safety Hazards

Accidents

Sources

Process

Pipelines

Production

Methanearomatic and aliphatic petroleum hydrocarbons

Condensate tanks

Production

MethaneAromatic and aliphatic petroleum hydrocarbons

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Table 2. (Continued). Sources, processes, and hazards associated with oil exploration.

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Nonchemical hazards

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch007

Table 3. Comparison of oil production and associated water impacts in ND and SD. Reproduced with permission from reference (19). Copyright 2012 South Dakota Department of Environment & Natural Resources. SD

ND

Rig Count

1

>200

New oil Wells ( Per year)

12

>2000

Known oil reserves

Red river formation; Minnelusa wells

Bakken shale

Water consumption

0.015 million gallons/well

2-4 million gallons/well

Well Depth

8500 ft

10000 ft

Well cost

$2.5 million

$7.9 million

According to the ND State Water Commission, horizontally-drilled oil wells in ND consume nearly 4% of the total water consumption (12,629 acre feet surface) (Figure. 2). Water consumption for HF is almost equivalent to the total rural water consumption in ND. As per Cere’s report (17), oil development in ND consumed 5.5 billion gallons of water in 2012 alone. With an estimated development of 40,000-45,000 new oil wells in coming two decades, we can anticipate tremendous water stress in the region (20). The constant depletion of groundwater resources, coupled with limitations in surface water in the region, could increase competition among farmers, ranchers, shale energy producers and municipal users. Further, with increasing concerns for water depletion, obtaining a ground water permit will be a challenging task in the region. On a similar note, a regulatory dispute between the state of ND and the Army Corps of Engineers has restricted industrial water withdrawals from Lake Sakakwea (major reservoir of the Missouri River) (21–23). Nearly 78 percent of the water in the Bakken is obtained from six counties including McKenzie, Williams, Mountrail, Dunn, Richland, and Roosevelt. Figure 3 shows the highest water use counties in the Bakken and the corresponding stress category.

161 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch007

Figure 2. Consumptive water use in ND. Adapted with permission from reference (23). Copyright 2014 North Dakota State Water Commission.

Figure 3. Highest Water use counties in the Bakken by water stress Category. Adapted with permission from reference (17). Copyright 2014 CERES. 162 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch007

4.2. Wastewater Management The HF in the Bakken generates two major types of wastewater (i.e., flowback and produced water). The flowback water is a portion of injected water that returns back to the surface, while the produced water is a naturally-occurring water that exists in the formation and is “produced” along with hydrocarbons throughout the lifetime of well. Both flowback and produced waters are contaminated with drilling muds, fracturing chemicals, methane, petroleum condensate, salts, metals, and naturally occurring radioactive materials (NORM). There are three options for managing wastewater generated during HF: i) Class II injection wells guided by Underground Injection Control regulations, ii) Water treatment facilities, and iii) Reuse opportunities within the oil field. The produced water and flowback water at Bakken are currently stored in surface pits prior to disposal in Class II injection wells. In ND, the wastewater is injected into Class II injection wells at a depth of one-half mile to one mile to prevent migration of fluids into adjacent formations and fresh water zones.

4.2.1. Type II Characteristics of Wastewater from the Bakken Oil Fields With nearly 12,000 unconventional oil wells in the Bakken Play, and each well consuming nearly 3-8 million gallons of water throughout its life time, the Bakken fields can be expected to generate an enormous amount of wastewater. The flowback water from Bakken is high in total dissolved solids (~300,000 mg/L) and includes a variety of fracturing chemicals introduced during the drilling operations. A majority of these chemicals can be associated with toxic, corrosive, and acidic characteristics. It is difficult to predict the overall hazard of wastewater due to unknown information for proprietary chemicals included in fracturing fluids. However, it may be conservative to state that the discharge of untreated wastewater from the Bakken oil fields can threaten surface water bodies and municipal water treatment plants. For instance, the produced/flowback water from the Bakken has the highest amounts of Total Dissolved Solids (TDS) of any producing U.S. region (24). Table 4 shows a typical composition of three samples collected from three wells which had a cumulative flowback water of 3,500 bbp. As shown in Table 4, the flowback water has the highest concentration of sodium (47,000 to 75,000 mg/L), followed by calcium (7,500 to 13,500 mg/L), and magnesium (600 to 1,750 mg/L). Among anions, chloride has the highest concentration (90,000 to 133,000 mg/L). The water pH was slightly acidic (