Environmental Considerations Associated with Hydraulic Fracturing Operations: Adjusting to the Shale Revolution in a Green World [1 ed.] 1119336090, 9781119336099

Citation preview

Environmental Considerations Associated with Hydraulic Fracturing Operations

Environmental Considerations Associated with Hydraulic Fracturing Operations Adjusting to the Shale Revolution in a Green World

James A. Jacobs

Pt. Richmond, CA, USA

Stephen M. Testa

Mokelumne Hill, CA, USA

This edition first published 2019 © 2019 John Wiley & Sons, Inc. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, except as permitted by law. Advice on how to obtain permission to reuse material from this title is available at http://www.wiley.com/go/permissions. The right of James A. Jacobs and Stephen M. Testa to be identified as the authors of this work has been asserted in accordance with law. Registered Office John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, USA Editorial Office 111 River Street, Hoboken, NJ 07030, USA For details of our global editorial offices, customer services, and more information about Wiley products visit us at www.wiley.com. Wiley also publishes its books in a variety of electronic formats and by print‐on‐demand. Some content that appears in standard print versions of this book may not be available in other formats. Limit of Liability/Disclaimer of Warranty In view of ongoing research, equipment modifications, changes in governmental regulations, and the constant flow of information relating to the use of experimental reagents, equipment, and devices, the reader is urged to review and evaluate the information provided in the package insert or instructions for each chemical, piece of equipment, reagent, or device for, among other things, any changes in the instructions or indication of usage and for added warnings and precautions. While the publisher and authors have used their best efforts in preparing this work, they make no representations or warranties with respect to the accuracy or completeness of the contents of this work and specifically disclaim all warranties, including without limitation any implied warranties of merchantability or fitness for a particular purpose. No warranty may be created or extended by sales representatives, written sales materials or promotional statements for this work. The fact that an organization, website, or product is referred to in this work as a citation and/or potential source of further information does not mean that the publisher and authors endorse the information or services the organization, website, or product may provide or recommendations it may make. This work is sold with the understanding that the publisher is not engaged in rendering professional services. The advice and strategies contained herein may not be suitable for your situation. You should consult with a specialist where appropriate. Further, readers should be aware that websites listed in this work may have changed or disappeared between when this work was written and when it is read. Neither the publisher nor authors shall be liable for any loss of profit or any other commercial damages, including but not limited to special, incidental, consequential, or other damages. Library of Congress Cataloging‐in‐Publication Data applied for Hardback ISBN: 9781119336099 Cover Design: Wiley Cover Image: Courtesy of James A. Jacobs Set in 10/12pt Warnock by SPi Global, Pondicherry, India Printed in United States of America 10 9 8 7 6 5 4 3 2 1

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Contents List of Figures  xvii List of Tables  xxvii Foreword  xxxi Acknowledgments  xxxiii 1 Introduction  1

1.1 ­Energy and the Shale Revolution  1 1.2 ­Cultural Influences  3 1.3 ­Conventional Versus Unconventional Resources  4 1.4 ­Well Simulation  5 1.4.1 Types of Well Stimulation Technologies  6 1.4.2 Terminology 16 1.5 ­Hydraulic Fracturing in the United States  16 1.6 ­Environmental Considerations  17 1.6.1 Environmental Stewardship  19 1.6.2 The New Energy Landscape and Environmental Challenges  21 1.7 Exercises  22 References  22 Suggested Reading  23 Historical Development from Fracturing to Hydraulic Fracturing  25 2.1 ­Introduction  25 2.2 ­Explosives and Guns (1820s–1930s)  26 2.2.1 The Battle of Fredericksburg and the Roberts Petroleum Torpedo Company  28 2.2.2 Well Casing Perforators  31 2.2.3 The First Perforating Guns  33 2.2.4 Bazooka Technology  33 2.2.5 Matrix Acidizing Treatment  34 2.2.6 The Sulfur King  35 2.2.7 Modern Age of Acidizing  38 2.3 ­The Birth of the Petroleum Engineer (1940s–1950s)  38 2.3.1 The Hydrafrac Process  38 2.4 ­Going Nuclear During Peak Oil (1960s to Mid‐1970s)  39 2.4.1 Project Plowshare  40 2.4.2 Project Gasbuggy  41 2.4.3 Project Rulison and Project Rio Blanco  41 2.4.4 Project Bronco  41 2.4.5 Project Wagon Wheel  41 2.4.6 Former Union of Soviet Socialist Republics (USSR) Program  43 2.4.7 Other Innovations  44 2.4.8 Peak Oil  44 2.5 ­The Rise of the Unconventionals (Mid‐1970s to Present)  45 2.5.1 Horizontal Drilling  46

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2.5.2 The Carter Years and the Role of the Feds  48 2.5.3 Recent Innovations in Fluids and Additives (2000–2010)  49 2.6 Exercises  49 References  50 Suggested Reading  51 Geology of Unconventional Resources  53 3.1 ­Introduction  53 3.2 ­Oil Shale Nomenclature  54 3.3 ­Oil Shale Classification  54 3.4 ­Types of Shale Formations Based on Production  56 3.4.1 Shale Gas  57 3.4.2 Tight Natural Gas  57 3.4.3 Tight Oil  59 3.4.4 Coalbed Natural Gas  59 3.5 ­Geology of United States Shale Deposits  60 3.5.1 Green River Formation  60 Eastern Devonian–Mississippian Oil Shale Case Study  62 3.5.2 3.5.3 Specific Shale Plays  63 3.5.4 Barnett Shale  66 3.5.5 The Marcellus Shale  69 3.5.6 The Fayetteville Shale  69 3.5.7 The Haynesville Shale  71 3.5.8 The Woodford Shale  71 3.5.9 The Antrim Shale  71 3.5.10 The New Albany Shale  72 3.5.11 The Bakken Formation and Three Forks Formations  72 3.5.12 The Monterey Formation/Monterey Temblor  73 3.5.13 Geology of World Shale Deposits  75 3.5.14 Estimated Worldwide Gas Shale Resources  75 3.6 ­The Role of Natural Fractures  75 3.7 Exercises  76 References  77 Suggested Reading  79

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Overview of Drilling and Hydraulic Fracture Stimulation Techniques for Tight Oil and Gas Shale Formations  81

4.1 ­Introduction  81 4.1.1 Overview of the Exploration–Production Life Cycle  82 4.1.2 Phases of Activity  82 4.2 ­Phase 1: Prospect Generation for Unconventional Oil and Gas Targets  85 4.2.1 Unconventional Resource Prospecting  85 4.2.2 Geologic and Reservoir Study  86 4.2.3 Evaluation of Areal Extent  86 4.2.4 Site‐Specific Technical Details  86 4.2.5 Geochemistry and Basin History  87 4.2.6 Unconventional Resource Issues  88 4.2.7 Estimating Oil and Gas  89 4.2.8 Original Oil in Place (OOIP)  89 Original Gas in Place (OGIP)  90 4.2.9 4.2.10 Risk Factors  90 4.2.11 Geochemistry Studies  92 4.2.12 Geophysical Data Acquisition  92 4.2.12.1 Types of Geophysical Surveys  92 4.3 ­Phase 2: Planning Phase  92

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4.3.1 Leases  93 4.3.2 Drilling Permit Process and Public Participation  93 4.3.3 Drilling Pad Construction  94 4.4 ­Phase 3: Drilling  94 4.4.1 Drilling Rig  95 4.4.2 Circulation System  97 4.4.3 Logging Equipment  101 4.4.3.1 Mud Logging  102 4.4.3.2 Wire Line Logging  102 4.4.3.3 Logging While Drilling  104 4.4.4 Fluid Management System  104 4.4.5 Drill String  106 4.4.6 Casing System  107 4.4.7 Cementing System  109 4.5 ­Brief Overview of Hydraulic Fracturing  109 4.6 ­Operators and Contractors  111 4.7 ­Phase 4: Completion  111 4.8 ­Overview of Hydraulic Fracturing Process  115 4.8.1 Technology Improvements  118 4.9 ­Single‐Stage Treatment  119 4.9.1 Four‐Phase Treatment  119 4.9.1.1 Treatment Phase 1: Acid Injection  120 4.9.1.2 Treatment Phase 2: Slickwater Injection  121 4.9.1.3 Treatment Phase 3: Proppant Sequence Injection  121 4.9.1.4 Treatment Phase 4: Flushing Phase  123 4.10 ­Fluid Recovery and Waste Management  123 4.10.1 Flowback Fluids  123 4.11 ­Oil and Gas Production  123 4.11.1 Residual Oil Zones: Unconventional Target  124 4.11.2 Coproduced Water  126 4.12 Naturally Occurring Radioactive Material (NORM)  126 4.12.1 Transportation Challenges  127 4.12.2 Lithium Source  127 4.12.3 Oil and Gas Production Limits  127 4.13 ­Workshop #1: Gas Well Economic Limit  128 4.14 ­Workshop #2: Oil Well Economics  129 4.15 Well Destruction  129 4.15.1 Site Restoration  130 4.16 ­Summary  131 4.17 Exercises  131 References  132 Suggested Reading  134 5

Overview of Impacts from Tight Oil and Shale Gas Resource Development  137

5.1 ­Introduction  137 5.1.1 Precautionary Principle  137 5.2 ­Potential Impacts and Risks of Spills  137 5.3 ­Significance of Impacts  137 5.4 ­Overview of the Five Main Resource Categories  138 5.4.1 Air Resources  139 5.4.2 Geological and Soil Resources  145 5.4.3 Ecological Resources  145 5.4.4 Land Use Resources and Socioeconomics  145 5.4.5 Water Resources  145 5.5 ­Primary Wastes Generated  146

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5.6 ­Site‐specific Impact Analysis  146 5.6.1 Impacts from Phase 1: Prospect Generation  147 5.6.1.1 Geochemical Sampling  147 5.6.1.2 Geophysical Surveys  147 5.6.2 Impacts from Phase 2: Planning and Site Preparation  148 5.6.3 Impacts from Phase 3: Drilling  149 5.6.3.1 Blowouts 149 5.6.3.2 Well Control  150 5.6.3.3 Fracking‐Related Surface Blowouts  150 5.6.3.4 Underground Blowouts  150 5.6.4 Impacts from Produced Fluids and Gases at Oil and Gas Fields  150 5.6.4.1 Constituents of Environmental Concern  151 5.6.5 Impacts from Natural Gas  151 5.6.6 Impacts from Crude Oil  152 5.6.7 Impacts from Phase 4: Well Completion and Hydraulic Fracture Stimulation  154 5.6.8 Impacts from Phase 5: Fluid Recovery and Waste Management  154 5.6.9 Impacts from Naturally Occurring Radioactive Materials (NORMS)  155 5.6.10 Impacts from Other Miscellaneous Hazardous Compounds  156 5.6.11 Impacts from Phase 6: Oil and Gas Production  156 5.6.12 Impacts from Drilling Fluids and Production Wastes  157 5.6.13 Impacts from Specific Oil and Gas Field Locations  159 5.6.14 Impacts from Historic and Abandoned Oil, Gas, and Water Wells  159 5.6.15 Impacts from Transportation Activities  161 5.6.16 Impacts from Phase 7: Well Decommissioning and Site Restoration  161 5.7 ­Summary of Resources and Issues  163 5.8 ­Summary  174 5.9 Exercises  176 References  177 Suggested Reading  179 Surface and Groundwater Risks, Resource Quality Management, and Impacts  183 6.1 ­Introduction  183 6.2 ­The Hydraulic Fracturing Water Cycle  183 6.2.1 Water Acquisition  184 6.2.2 Chemical Mixing  185 6.2.3 Well Injection  187 6.2.4 Produced Water Handling  187 6.2.5 Wastewater Disposal and Reuse  187 6.3 ­Potential Impacts on Drinking Water Resources  188 6.3.1 Vertical Distance Between Drinking Water Resources and Hydraulic Fracturing  188 6.4 ­Public Water System (PWS) Sources  189 6.4.1 Vertical Distance Between PWS Sources and Hydraulic Fracturing Activities  190 6.4.2 Lateral Distance Between PWS Sources and Hydraulic Fracturing Activities  190 6.5 ­Underground Injection Control  190 6.5.1 The Underground Injection Control Program  190 6.5.2 Water Quality and Aquifer Exemptions  192 6.5.2.1 Abandoned Wells  194 6.6 ­Case Histories  196 6.7 Exercises  198 References  198 Suggested Reading  199

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Induced Seismicity  203 7.1 ­Introduction  203 7.2 ­Measuring Earthquake Severity  204

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7.2.1 Seismic Intensity and Magnitude  205 7.2.2 Measuring the Size of an Earthquake  207 7.3 ­Anthropogenic‐Induced Earthquakes  208 7.4 ­Mechanics of Anthropogenic‐Induced Earthquakes  210 7.5 ­Induced Microseismicity and Microseismic Monitoring  212 7.6 Exercises  212 References  213 Suggested Reading  213 Air Quality Resources and Mitigation Measures  215 8.1 ­Introduction  215 8.2 ­Unconventional Resource Extraction and Air Quality  215 8.3 ­Sources of Air Emissions  215 8.3.1 Flares  217 8.3.2 Fugitive Emissions  218 8.3.3 Air Quality and Frac Sands  219 8.4 ­Worker Safety  220 8.4.1 Worker Exposure  220 8.4.2 Construction Particulates  221 8.4.3 Silica Dust  221 8.4.4 Silica Dust Levels  221 8.4.4.1 Silica Dust Mitigation Measures  222 8.4.4.2 Protecting Workers from Silica Dust  226 8.4.4.3 Protecting the Public from Silica Dust  226 8.4.5 Diesel Exhaust and Diesel Particulate Matter  227 8.4.5.1 Controlling Diesel Particulate Matter  227 8.4.6 Hydrogen Sulfide Gas  228 8.4.7 Aldehyde Exposure  228 8.4.8 Volatile Organic Compounds  228 8.4.9 Toxic Fungus  230 8.4.10 Radon 230 8.5 ­Gas Leaks and Vapor Sampling  230 8.6 ­Biogenic and Thermogenic Hydrocarbon Gases  232 8.7 ­Gas Leaks  233 8.7.1 Coalbed Methane  233 8.7.2 Gas Explosions  233 8.7.3 Processed Natural Gas  234 8.7.4 Vapors and Odor Sensitivity  234 8.8 ­Soil Vapor Intrusion Overview  234 8.8.1 Environmental Factors Description  234 8.8.2 Natural Factors Affecting Gas Migration into Buildings  235 8.8.2.1 Soil Conditions  235 8.8.2.2 Volatile Chemical Concentrations  235 8.8.2.3 Source Location  235 8.8.2.4 Groundwater Conditions  235 8.8.2.5 Surface Confining Layer  235 8.8.2.6 Fractures 235 8.8.2.7 Underground Conduits  235 8.8.2.8 Weather Conditions  236 8.8.2.9 Biodegradation Processes  236 8.8.3 Architectural Factors Affecting Gas Migration into Buildings  236 8.8.3.1 Building Factor  236 8.8.3.2 Heated Building  236 8.8.3.3 Air Exchange Rates  236 8.8.3.4 Foundation Type  236

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8.8.3.5 Foundation Integrity  236 8.8.3.6 Subsurface Conduits  237 8.8.4 Other Factors Affecting Indoor Air Quality  237 8.8.5 Other Source Descriptions for Indoor Air Degradation  237 8.8.5.1 Outdoor Air  237 8.8.5.2 Attached or Underground Garages  237 8.8.5.3 Off‐Gassing Processes  237 8.8.5.4 Household Products  237 8.8.5.5 Occupant Activities  237 8.8.5.6 Indoor Emissions  237 8.9 ­General Approach to Evaluating Soil Vapor Intrusion  237 8.9.1 Air and Vapor Conversion Factors  237 8.9.2 Types of Air and Vapor Samples  238 8.9.3 Photoionization Detector for Vapor Screening  238 8.9.4 Active Air Screening and Monitoring  238 8.9.5 Passive Air Monitoring  238 8.9.6 Passive Air Screening  240 8.9.7 Passive Soil Vapor Sampling  240 8.9.8 Active Soil Gas Sampling  243 8.9.9 Laboratory Analysis  245 8.9.10 Vapor Sample Collection  245 8.9.11 Analytical Methods  246 8.9.12 Analytical Approach  248 8.10 ­Summary  248 8.11 Exercises  249 References  249 Suggested Reading  253 Land Use Resources and Socioeconomics  255 9.1 ­Introduction  255 9.2 ­Community Concerns and Land Use Planning  255 9.2.1 Community Issues  257 9.2.2 Best Management Approach  258 9.2.3 Setbacks  258 9.2.4 Cultural Resource Protection and Historic Resource Protection  258 9.3 ­Environmental Justice  259 9.4 ­Land Disturbance  259 9.4.1 Abiotic Ecosystem Processes  260 9.4.2 Acid Rock Drainage  260 9.4.3 Acid Rock Drainage Mitigation  260 9.4.4 Native Plant Communities  260 9.4.5 Invasive Plants  261 9.4.6 Land Disturbance Mitigation  261 9.5 ­Light Pollution  261 9.5.1 Lighting Mitigation Measures  261 9.5.2 Flaring Mitigation Measures  261 9.6 ­Noise  263 9.6.1 Speed of Sound  263 9.6.2 Measuring Sound  266 9.6.3 Measuring Noise and Modeling  267 9.6.4 On‐site Noise Investigation  267 9.6.5 Noise Studies  267 9.6.6 Background Sound Study  268 9.6.7 Initial Sound Study  268

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9.6.8 Noise Minimization Planning  269 9.6.9 Noise Mitigation Methods  269 9.7 ­Odor  270 9.8 ­Socioeconomics  271 9.8.1 Social Challenges  272 9.8.2 Community Issues  272 9.8.3 Mental Health Issues  272 9.9 ­Transportation and Traffic  272 9.9.1 Trackout  276 9.9.2 Truck Trips  277 9.10 ­Visual Aesthetics  277 9.11 ­Worker Safety  278 9.11.1 Worker Training and Education  278 9.12 ­Cumulative Impacts  278 9.13 Exercises  279 References  279 Suggested Reading  281 10 Ecological Resources  283 10.1 ­Introduction  283 10.2 ­Ecosystem Resources  283 10.2.1 Regulating Services  283 10.2.2 Supporting Services  283 10.2.3 Provisioning Services  283 10.2.4 Cultural Services  283 10.3 ­Ecosystem Resources  283 10.3.1 Ecosystem Issues  284 10.3.2 Drilling Pad as Attractant  284 10.3.3 Ecological Protection  284 10.3.4 Habitat Preservation and Invasive Species  284 10.3.5 Invasive Species  285 10.4 ­Interim Reclamation  286 10.4.1 Mitigation Measures  286 10.4.2 Supplies for Unconventional Oil and Gas Production  287 10.4.3 Oil Spills and Ecological Resources  287 10.4.4 Spills on Water  289 10.4.4.1 Shoreline Strategies  291 10.4.4.2 Shoreline Cleanup Methods  293 10.4.4.3 Oil Spill Prevention  293 10.4.4.4 Special Environmental Mapping and Modeling  293 10.4.4.5 Spill Responses on Water  294 10.4.4.6 Booms 294 10.4.4.7 Skimming Methods  295 10.5 ­Summary  295 10.6 Exercises  295 References  296 Suggested Reading  297 11

Legislative Trends Associated with Well Stimulation and Hydraulic Fracturing  299

11.1 ­Introduction  299 11.2 ­Federal Laws and Regulations  300 11.2.1 The Safe Drinking Water Act (SDWA)  300 11.2.2 Clean Water Act (CWA)  303 11.2.3 Emergency Planning and Community Right‐to‐Know Act  303

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11.2.4 Resource Conservation and Recovery Act  303 11.2.5 Comprehensive Environmental Response, Compensation, and Liability Act (Superfund Program)  304 11.2.6 Clean Air Act  304 11.3 ­State Legislation and Regulations  304 11.3.1 Disclosure Requirements  304 11.3.2 Legislative and Regulatory Trends for Certain States  307 11.4 ­Bans and Moratoriums  311 11.5 Exercises  313 References  313 Suggested Reading  314 Sampling, Exposure Pathways, and Site Conceptual Models  315 12.1 ­Introduction  315 12.1.1 Pathway Group 0  315 12.1.2 Pathway Group 1  315 12.1.3 Pathway Group 2  316 12.1.4 Pathway Group 3  317 12.1.5 Pathway Group 4  317 12.2 ­Hypothetical Scenario  317 12.2.1 Site Conceptual Model  318 12.2.2 Sampling Plan Objectives  320 12.2.2.1 Sampling Plan  320 12.2.3 Sampling Plan Elements  321 12.2.3.1 General Types of Chemicals Found at Oil and Gas Sites  322 12.2.4 Risk‐Based Decision‐Making  322 12.3 ­Overview of Sampling Procedures  322 12.3.1 Types of Samples  323 12.3.2 Discrete vs. Composite Samples  323 12.3.3 Composite vs. Incremental Sampling Methodology  323 12.3.4 In Situ vs. Disturbed Samples  325 12.3.5 Continuous Core vs. Discrete‐Depth Sampling  325 12.3.6 Permanent vs. Temporary Samples  325 12.3.7 Active vs. Passive Sampling Methodology  325 12.3.8 Cross‐Contamination  326 12.3.9 Air Sampling  326 12.3.10 Soil Vapor Sampling  327 12.4 ­Soil and Water Sampling  327 12.4.1 Borehole Methods  327 12.4.2 Direct Push Technology (DPT)  327 12.4.3 Sonic Drilling  328 12.4.4 Hollow Stem Auger (HSA)  328 12.4.5 Other Rotary Drilling Methods  329 12.5 ­Field Screening and Analysis  329 12.5.1 Gas Meters  329 12.5.2 Gas Colorimetric Glass Tubes  332 12.5.3 Field Water Meters  332 12.5.4 Water and Soil Field Kits  332 12.6 ­Other Considerations  332 12.6.1 Soil and Rock Heterogeneity  332 12.6.2 Laboratory Terms  332 12.6.3 Quantitative Laboratory Methods  333 12.6.4 Chemistry of Petroleum Hydrocarbons  334 12.6.5 Unconventional Oil and Gas Chemical Additives  337 12.6.6 Unconventional Oil and Gas Parameters of Interest  337

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12.6.7 Unconventional Oil and Gas Chemicals of Interest  338 12.7 ­Fate and Transport  339 12.7.1 Organic Carbon–Water Partitioning Coefficient (Koc)  339 12.7.2 Distribution Coefficient (Kd)  339 12.7.3 Henry’s Law Solubilities  339 12.7.4 Aqueous Solubility (S)  339 12.7.5 Water Well Quality in Areas of Unconventional Oil and Gas Development  339 12.7.6 Laboratory Analysis for Water Wells  341 12.8 ­Summary  342 12.9 Exercises  342 References  345 Suggested Reading  347 13

Financial Issues: Real Estate Values and Selected Contracting Costs of Repairs, Assessment, or Mitigation Activities for Unconventional Oil and Gas Production Areas  351

13.1 ­Introduction  351 13.2 ­Valuation of Real Estate  351 Real Estate  352 13.2.1 13.2.2 Operational Timing  352 13.2.3 Split Estate  352 13.2.4 Landowner Royalty Payments  352 13.2.5 Future Use  353 13.2.6 Oil and Gas Production 2000–2015  354 13.2.7 Value of Residential Real Estate  355 13.2.8 Perceptions  355 13.2.9 Property Value Survey  356 13.2.10 Home Prices near Well Sites  356 13.3 ­Water Supplies  357 13.3.1 Domestic Water Well Costs  357 13.3.2 Public Water Supplies  357 13.3.3 Water Treatment Systems  358 13.4 ­Other Mitigating Costs  358 13.4.1 Soundproofing Equipment Shed  358 13.4.2 Road Construction Projects  358 13.4.2.1 Truck Trip Estimates  358 13.4.2.2 Cost of Road Construction  360 13.5 ­Mitigation of Subsurface Impacts  362 13.5.1 Orphan Well Survey  362 13.5.2 Orphan Well Destruction  362 13.5.3 Subsurface Investigations  363 13.5.4 Hypothetical Case: Suspected Pipeline Spill Project  364 13.5.4.1 Cost of Hypothetical Soil Sampling Project  364 13.6 ­Remediation Strategies  365 13.6.1 Risk Management Strategies  366 13.6.2 Lender Risk Reduction  366 13.6.3 Green and Sustainable Remediation  366 13.6.3.1 Green and Sustainable Remediation Tools and Software  366 13.6.3.2 SiteWise™ Tool for Green and Sustainable Remediation  366 13.6.3.3 Sustainable Remediation Tool (SRT)  368 Natural Attenuation Software (NAS)  368 13.6.4 13.6.5 Mass Flux Toolkit  369 13.6.6 Federal Remediation Technologies Roundtable Decision Support Tools  369 13.6.7 Risk-Based Decision-Making  369 13.7 ­Budgeting for Costs  369

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13.7.1 Low‐Cost Cleanup Projects  369 13.7.2 Medium-Cost Cleanup Projects  370 13.7.3 Higher-Cost Cleanup Projects  370 13.7.4 Railway Cleanup Costs  371 13.7.5 Pipeline Leaks  371 13.8 ­Summary  372 13.9 ­Exercises  373 References  374 Suggested Reading  375 Legal Considerations and Case Law  377 14.1 ­Introduction  377 14.2 ­Environmental Tort Litigation  382 14.3 ­Environmental/Citizen Action and Industry Challenges Litigation  383 14.4 ­Infrastructure‐Related Litigation  384 14.5 ­Traditional Oil and Gas Issues in Nontraditional Forums  384 14.6 ­Fracking Bans and Moratoriums  384 14.7 ­Summary  386 14.8 Exercises  387 Reference  387 Suggested Reading  387

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15 Spills, Forensic Evaluation, and Case Studies  389 15.1 ­Introduction  389 15.2 ­Spill Studies  389 15.2.1 US EPA Study  389 15.2.2 Patterson and Others (2017)  390 15.3 ­Spill Settlement Case Study  392 15.3.1 Rail Case Studies  393 15.3.2 Bakken Crude Oil Characteristics: Two Studies  394 15.3.3 Summary of Bakken Crude Oil Spill Incidents  394 15.3.4 Fate and Transport of Spilled Crude  394 15.3.5 Combustion  398 15.3.6 DOT‐117 Tank Car Design  398 15.4 ­Violations  399 15.5 ­Forensic Analysis  399 15.5.1 Gas Chromatograms  400 15.5.2 Tentatively Identified Compounds (TICs)  401 15.5.3 Piper Diagrams  401 15.5.4 Biomarkers  403 15.5.4.1 Compound‐Specific Isotope Analysis  403 15.5.4.2 CSIA of Biomarkers  404 15.5.5 Chemical and Biological Transformations  404 15.5.6 Chemical Ratios  406 15.5.7 Geochemical Tracers  406 15.5.7.1 2‐n‐Butoxyethanol Tracer Case Study  407 15.5.8 Isotopes  407 15.5.8.1 Hydrogen and Oxygen Isotopes  407 15.5.8.2 Carbon and Methane Isotopes  407 Forensic Isotope Analysis  408 15.5.9 15.5.10 Boron and Strontium Isotope Ratios  409 15.5.11 Radioactive Isotopes  410 15.5.12 Case Studies  411

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15.5.12.1 Water Isotope Case Study in Northern California  411 15.5.12.2 Water Isotope Case Study in Northeast Pennsylvania  412 15.6 ­Prospective and Retrospective Case Studies  413 15.6.1 US EPA Retrospective Case Study  414 15.6.2 US EPA Retrospective Study Approach and Sampling Activities  415 15.6.2.1 Northeast Pennsylvania Case Study  416 15.6.3 Main Findings  420 15.6.3.1 Southwest Pennsylvania Case Study  421 15.6.3.2 North Texas Case Study  424 15.6.3.3 West North Dakota Case Study  427 15.6.3.4 Southeast Colorado Case Study  430 15.6.4 Summary of US EPA Retrospective Studies  438 15.6.4.1 Other Case Studies in Northeastern Pennsylvania  439 15.7 Exercises  439 References  440 Suggested Reading  446 16 Conclusions 453 Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F Appendix G Appendix H Appendix I Appendix J Appendix K Index 527

Selected University Studies, State, and Federal Reports  455 Glossary  461 List of Acronyms and Abbreviations  467 Conversions  473 Summary of Potential Job Hazards During Hydraulic Fracture Stimulation Process   477 Chemical Additives Used in the High‐Volume Hydraulic Fracturing Operations  481 Exposure Planning, Emergency Response, and Toxicity Tables  485 Selected Sampling Methods and Documentation  493 Environmental Checklists  503 Metric Conversion of Table 3.4 (Metric Units in Bold italics)  523 US Crude Oil Prices 1859–2016  525

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List of Figures Figure 1.1 From the start of 2007 through the end of 2012, total US private sector employment increased by more than one million jobs, about 1%. Over the same period, the oil and natural gas industry increased by more than 162 000 jobs, a 40% increase (USEIA 2013). 2 Figure 1.2 Oil–gas basins and shale gas plays in the lower United States (API 2015). 2 Figure 1.3 Fracking has reached the local coffee houses in downtown Sacramento, California, as reported by the Sacramento News and Review on 29 March 2012.  3 Figure 1.4 Schematic diagram of the different types of onshore natural gas plays. Conventional resources are buoyancy‐driven hydrocarbon accumulations, with secondary migration and structural and/or stratigraphic closures. Unconventional continuous gas accumulations in basin centers and transition zones are controlled by expulsion‐driven secondary migration and capillary seal.  4 Figure 1.5 US dry natural gas production in trillion cubic feet and billion cubic feet per day for shale resources that as of 2015 remain the dominant source of US natural gas production growth (USEIA 2015). Note that shale gas production becomes significant in 2010 and is projected to be dominant in 2040.  5 Figure 1.6 An interesting statistic is that only about one‐third of the worldwide oil and gas reserves are conventional in nature – the remainder are unconventional, which includes tight gas, coalbed methane (CBM), methane hydrates, shale gas, shale oil, heavy oil, and tar sands.  6 Figure 1.7 Greater length of producing formation is exposed to the wellbore in a horizontal well (A) than in a vertical well (B) (USEIA 1993).  6 Figure 1.8 Distribution of about 986 600 hydraulically fractured wells in the contiguous United States from 1947 to 2010, excluding wells situated offshore and in Alaska.  17 Figure 1.9 Distribution of about 278 000 hydraulically fractured wells in the contiguous United States from 2000 to 2010, excluding wells situated offshore and in Alaska.  18 Figure 1.10 The sustainability framework represents the world as three interrelated and interacting systems: economy, society, and environment. The arrows in the figure show the flows among the three systems.  20 Figure 2.1 Historic photo of the Drake well circa 1859 (left) and Edwin Drake (right) who was neither a colonel nor a driller, but he was courageous and ambitious and did have a commitment to the new technology.  26 Figure 2.2 Lt. Col. Edward A.L. Roberts in full Union army military regalia. Working with his brother, Walter B. Roberts, they formed the Roberts Torpedo Company in 1865 and patented their invention in 1866.  28 Figure 2.3 The Roberts Torpedo barn factory was located far from populated areas due to a tendency of unintended explosions.  29 Figure 2.4 Stock certification for the Roberts Petroleum Torpedo Company. Established in 1885, numerous patents provided Roberts a monopoly on torpedoes in the early years of the oil industry.  30 Figure 2.5 Schematic of E.A.L. Roberts Torpedo, Patent No. 59936, 20 November 1866. The cylindrical torpedo would be filled with gunpowder and later nitroglycerin and lowered into the well and ignited by dropping a weight referred to as a “go‐devil” along the suspension wire onto a percussion cap.  31 Figure 2.6 A torpedo shell being filled with nitroglycerin, and was known as “shooting the well.” Illegal shooting led to the term “moonlighting.”  31 Figure 2.7 Roberts Petroleum Torpedo Company’s advertisement undated.  32 Figure 2.8 View of Holmden Street from First Street in Pithole, one of the early oil boomtowns, now a Pennsylvania oil ghost town near Titusville, Pennsylvania. The site was cleared of overgrowth and was donated to the Pennsylvania Historical and Museum Commission in 1961. A visitor center, containing exhibits pertaining to the history of Pithole, was built in 1972. Pithole was listed on the National Register of Historic Places in 1973. None of the historic structures survived.  33

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Figure 2.9 A 1902 invention used a scissors‐like expanding mechanism to drive and then retract “perforating levers” through the casing. 34 Figure 2.10 The 1930s brought various downhole “guns” that shot steel‐jacketed bullets through casing and about a foot into the producing formation. 34 Figure 2.11 Although not a “machine gun” as noted in this August 1938 Popular Science Monthly article, vital production technologies provide explosive energy to cut through casing and strata and produce petroleum.  35 Figure 2.12 Improved perforating technology evolves from the rocket grenade used in the Army’s M1A1 “bazooka.”  36 Figure 2.13a US Patent Office No. 2,947,250, 1960.  36 Figure 2.13b Henry Mohaupt’s revolutionary idea was to use a conically hollowed‐out explosive charge to direct and focus the detonation’s energy.  36 Figure 2.14 US chemist Herman Frasch (1851–1914) developed the sulfur mining process and a method for removing sulfur from crude oil, both referred to as the Frasch process.  37 Figure 2.15 Herman Frasch 1896 US Patent No. 556,669 illustrating the increasing flow of oil in a well.  37 Figure 2.16a Sequence of steps in the hydrafrac process.  38 Figure 2.16b Well setup in the hydrafrac process.  39 Figure 2.17 Total number of hydraulic fracturing treatment records associated with wells drilled from 1947 through 2010 and the top 95% of proppant, treatment fluid, and additive types. Shown are hydraulic fracturing records (1 763 815 records) (a): treatment fluid records (1 593 683 records) (b) and additive records (330 501 total) (c).  40 Figure 2.18 Scientists lower a 13 ft (4 m) by 1.5 ft (0.5 m) diameter nuclear warhead into a well in New Mexico. The experimental 29‐kiloton Project Gasbuggy device will be detonated at a depth of 4240 ft (1292 m).  43 Figure 2.19 Gasbuggy: “Site of the first United States underground nuclear experiment for the stimulation of low‐productivity gas reservoirs.” 44 Figure 2.20 The conceptual Project Wagon Wheel showing predicted explosive effects.  45 Figure 2.21 Hubbert’s curve and peak. 46 Figure 2.22 US dry natural gas production in trillion cubic feet and billion cubic feet per day for shale resources, which as of 2015 remains the dominant source of US natural gas production growth (US EIA 2015). Note that shale gas production becomes significant by 2010 and is projected to be dominant by 2040.  46 Figure 2.23 Greater length of producing formation is exposed to the wellbore in a horizontal well (A) than in a vertical well (B) (US EIA 1993).  47 Figure 2.24 J.S. Campbell flexible driving shaft. 47 Figure 3.1 Petrographic classification of oil shales (Hutton 1987).  56 Figure 3.2 Global distribution of structural basins with shale gas and oil in 38 countries (EIA 2011). Dark shaded areas are assessed basins with assessed resource estimates. Light shaded areas are basins without assessed resource estimates.  57 Figure 3.3 United States shale gas plays and associated production from year 2000 to 2015 (EIA 2015).  58 Figure 3.4 Major tight gas plays within the United States (EIA 2010).  58 Figure 3.5 US tight oil production per selected play (EIA 2015). 59 Figure 3.6 Distribution of coalbed methane fields throughout the lower United States (EIA 2009). 60 Figure 3.7a Areas underlain by the Green River Formation in Colorado, Utah, and Wyoming (Dyni 2006).  61 Figure 3.7b Green River shale core showing 30% Total Organic Carbon (TOC) in a part of the basin, which is thermally immature. 62 Figure 3.8 Paleogeographic map showing the shoreline of the Late Devonian sea in the eastern United States and major areas of surface‐mineable Devonian oil shale. 63 Figure 3.9 Marcellus Shale Outcrop, Virginia.  64 Figure 3.10 Marcellus Shale from 3.5‐in diameter drill core containing a calcite‐filled vertical natural fracture. 64 Figure 3.11 Paleogeographic map of the Devonian basin with features labeled.  65 Figure 3.12 Ohio to Pennsylvania cross section (A–A′) of Middle and Upper Devonian strata in the Appalachian Basin. The Marcellus Shale is at the base of the sequence.  66 Figure 3.13 A stratigraphic chart for the Middle Devonian strata in the Appalachian Basin in a six‐state area.  66

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Figure 3.14 Geologic cross section drawn on the upper to middle Devonian strata from left to right: Alabama to New York. The cross section shows the massive sediment loading in the Appalachian Basin during the Devonian.  67 Figure 3.15 Major shale gas plays in the lower coterminous United States (US EIA, 2015).  68 Figure 3.16 Map of the Bend Arch–Fort Worth Basin Province (blue outline) and three Barnett Shale assessment units (USDOE 2009).  70 Figure 3.17 Generalized geologic cross section showing the various members of the Bakken Formation (LeFever 2007; Pollastro et al. 2013).  72 Figure 3.18 Illustration showing the areal extent of the Monterey Shale in California.  74 Figure 3.19 Typical Monterey formation outcrop in coastal southern California.  74 Figure 4.1 Example from the Bakken Formation in North Dakota shows the isolation of overburden from the target zone. A close‐up shows the perforations from the production casing into the rock, with the induced fractures. * Devonian‐Mississippian Bakken Formation is broken into the Lower Shale Member, the Middle Bakken Member (sandstone, dolomite, siltstone and shale) and the Upper Shale Member. Most of the Bakken Formation wells are drilled and completed in the Middle Bakken Member. 83 Figure 4.2 The estimated timing for operations for well drilling and oil production activities over the next 50 years from the Bakken Middle Member (US DOE 2009).  83 Figure 4.3 Generalized permeability range of oil and gas producing formations for unconventional and conventional reservoirs.  85 Figure 4.4 Naturally occurring heavy oil seeps from the Miocene Monterey Formation exposed at the beach in Point Arena in northern California show an immature oil source rock.  86 Figure 4.5a An example van Krevelen diagram of kerogen maturation is based on plotting the hydrogen index (H/C) as a function of the oxygen index (O/C) to assess the origin and maturity of kerogen and petroleum hydrocarbons (Kansas Geological Survey 2017).  88 Figure 4.5b Diagram showing depth and temperature of kerogen as it is converted into oil and eventually with increased temperature into thermogenic gas.  88 Figure 4.6 An example of a generalized burial history curve showing the burial of sediments with depth and associated hydrocarbon generation. The USGS chart shows a maximum Bakken Formation burial at about 50 million years ago in a 7969‐ft (2429‐m) ‐deep well in the high maturity Poplar dome area of Roosevelt County, Montana.  89 Figure 4.7 Seismic survey diagram showing a truck with an energy source such as a vibrator, with an example of a seismic section above (Kansas Geological Survey 2001).  93 Figure 4.8 Vibrating trucks used as an energy source in acquiring field data for a seismic reflection survey. 93 Figure 4.9 Typical drill pad with rotary rig and fluid tanks in March 2016 in the Bakken oil field in western North Dakota.  95 Figure 4.10 Circulatory pattern on a mud rotary drilling rig showing the direction of mud flow and main drilling components (BLM (2013) from BLM (1996)).  96 Figure 4.11 Drilling bits used in the oil and gas industry. (a) Fixed cutting bit with nozzles, (b and d) tricone bits, and (c) coring tool with hardened teeth for lithologic core collection (OSHA 2018; USGS 2013).  97 Figure 4.12 Core samples of a shale, placed and labeled in a core box from a drill site in Utah. Note the brittle nature of many of the zones.  98 Figure 4.13 Schematic of the mud circulating system including the drill bit, drill collar, annulus, drill pipe, kelly and swivel.  98 Figure 4.14 Example of the configuration of wire line logging tool commonly used when drilling for oil and gas with signal logging string (SLS) (a) and vertical seismic profiling (VSP) tool (b) (US DOE 2007). The log suite on the right (c) is just a small portion of data from a logging run (USGS).  102 Figure 4.15 A water impoundment at a natural gas drilling site in the Marcellus Shale gas play of southwestern Pennsylvania.  104 Figure 4.16 Pond liner regulations vary by state but are critical in protecting groundwater.  105 Figure 4.17 Side‐by‐side fluid storage tanks with top covers having secondary spill containment berms in northeast Pennsylvania.  106 Figure 4.18 Measurement while drilling (MWD) has been used for decades to aid in directional drilling.  107 Figure 4.19 Schematic of horizontal well with casing strings. No scale implied.  108

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Figure 4.20 Diagram showing fracture height (Fisher and Warpinski 2012) is on the left and chart showing top fracture height frequency (right) is from Davies et al. (2012). The collected figure was in US EPA (2016b).  110 Figure 4.21 Representation of common equipment at a shale gas drilling pad.  111 Figure 4.22 A hydraulic fracturing operation is underway at this drilling pad in the Marcellus Shale gas play in southwestern Pennsylvania.  112 Figure 4.23 Three well completion concepts: the cemented casing completion (left), the formation packer completion (center), and the open hole completion (right). Notes: not to scale; conductor casing not shown (US EPA 2015c).  112 Figure 4.24 Cemented casing completion method provides better well serviceability than open hole completions. This method may seal off natural fractures that could contribute to production. Example from the Bakken Formation in North Dakota.  113 Figure 4.25 Open borehole completion method has 7‐in‐diameter casing and then horizontal uncased 6‐in‐ diameter open borehole. This fast and low‐cost method uses a single fracture treatment with little control. Example from the Bakken Formation in North Dakota.  113 Figure 4.26 Uncemented, pre‐perforated liner method without annular isolation allows fluids to migrate inside or outside the liner. Perforations can be made with a perforation gun. Example from the Bakken Formation in North Dakota.  114 Figure 4.27 Positive annular isolation method uses an uncemented liner and swell packers, creating various stages. Example from the Bakken Formation in North Dakota.  114 Figure 4.28 Sliding sleeve method uses ball‐actuated sliding sleeves that are mechanical isolation devices to allow for better control of the injection fluids during the hydraulic fracturing process. Example from the Bakken Formation in North Dakota. Stages start at the farthest end of the wellbore and work toward the kickoff point.  115 Figure 4.29 Photo of downhole perforating gun used for hydraulic fracturing of a shale, in this case the Marcellus Shale in Pennsylvania. Reduction in hole area from inner to outer string is common. Retrieval of a perforation gun with significant burrs on the outside can damage packers, plugs, and seals.  115 Figure 4.30 Schematic of a perforation from a perforation gun (left) through the steel production liner, into cement, and into shale (right), creating perforation. Later slickwater with proppant will keep the perforation open and enlarge the fractures that will emanate from the perforation tip.  116 Figure 4.31 Pore pressure response in borehole during a perforation. SWB = static wellbore pressure starts at 5000 psi; formation pore pressure is about 4000 psi.  116 Figure 4.32 Summary of hydraulic fracturing process.  117 Figure 4.33 Detail of shale fractures in unconventional reservoir. Each group of closely spaced fractures is a stage, separated by the other stages when fractured by a plug, packer, or ball. The fracturing process usually starts at the end of the well first, returning to the kickoff point.  118 Figure 4.34 A generalized fracturing fluid and list of additives (US DOE 2009).  121 Figure 4.35 Photograph (top) of fine‐grained well‐sorted quartz sand used as a proppant in the Marcellus Shale.  122 Figure 4.36 Example of a four‐stage process (1, acid injection; 2, slickwater pad injection; 3, proppant injection; and 4, flush) showing pore pressures during initial fracturing, closure, and then the reopening of the fractures with the fluids and proppants.  122 Figure 4.37 Wellhead completion on two Marcellus Formation gas wells in northeastern Pennsylvania.  124 Figure 4.38 Marcellus gas production in northeast Pennsylvania (top) starts with installing wellheads (two seen in center of pad (1)). Note the erosion controls (wattles (2), gravel (3), and berm (4)). Fluid tanks (5) are still on‐site after fracking event a few days earlier. A few miles away, gas production (below) has been ongoing for a few years, with minimal disruption to the landowner. Once active drilling, hydraulic fracturing and production tests are completed, active gas production facilities should generally have minimal operational activities and disruption.  125 Figure 4.39 Close‐up schematic of the changes from initial oil saturation in a conventional oil reservoir (left) to mostly water saturation in a depleted or produced reservoir (right) that require enhanced oil recovery methods to improve production economics. Residual oil zones (ROZs), an unconventional oil source, start with high water saturation (right). Bottom figures provide the legends.  125 Figure 4.40 General concept of resource potential of the residual oil zone (ROZ), also called transition zone.  126 Figure 4.41 Summary of the simplified exploration–production life cycle.  127

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Figure 5.1 Locations of ~275 000 oil and gas wells that were drilled and hydraulically fractured between 2010 and 2013 (US EPA 2016b).  139 Figure 5.2 Water resources can be impacted by fluid spills. Conceptual model of a fluid spill from a drill site showing the environmental fate and transport of the released fluids (US EPA 2016b).  146 Figure 5.3 Conceptual diagram showing possible release pathways for subsurface fluids to migrate outside the well casing and borehole annulus. No scale implied (US EPA 2016b).  147 Figure 5.4 Improperly cased or damaged well (middle) or well with corroded casing (right) can impact a properly constructed well (left) by being a conduit into poor quality water units or even oil and gas zones.  160 Figure 5.5 Natural gas pipeline system from the well head to the customer (US DOT, PHMSA; 2017).  161 Figure 5.6 Figure showing the volumes of water usage in the United States for 2005 by category. Oil and gas operations are only part of the mining category that in total comprised about 1% of the total water used in the United States in 2005 (USGS).  165 Figure 5.7 Relationship between annual spill volume (left column), annual number of spills (center column), and annual throughput (right column) per annual spill volume (top row), annual number of spills (middle row), and cleanup costs per storage tank capacity (lowest row) (US GAO 1995).  166 Figure 5.8 In this satellite image of North America at night, natural gas flares from the Bakken Formation in Williston Basin in North Dakota can be seen from space. The night sky, once dark and bright with visible stars, has been obscured by oil production activities (NASA).  169 Figure 5.9 Photograph showing an active oil field situated within the Bolsa Chica wetland area in southern California.  169 Figure 5.10 A modern drilling operation has been operating for decades camouflaged as a high‐rise condo building with palm trees in the background in the Long Beach, California, harbor.  172 Figure 5.11 Urban drilling at the Packard drill site on Pico Boulevard in West Los Angeles, California, is at the edge of a residential area.  173 Figure 5.12 An urban drilling pad in the San Vicente oil field in the Los Angeles Basin is in Beverly Hills.  173 Figure 5.13 Schematic illustrating a typical injection well.  174 Figure 6.1 A generalized landscape depicting simplified activities of the hydraulic fracturing water cycle, their relationship to each other, and their relationship to drinking water resources. Arrows depict the movement of water and chemicals (US EPA 2017).  184 Figure 6.2 Water budgets illustrative of hydraulic fracturing water management practices in the (a) Marcellus Shale in the Susquehanna River Basin between ~2008 and 2013 and the (b) Barnett Shale in Texas between ~2011 and 2013. Note that reused hydraulic fracturing wastewater as a percentage of injected fluid differs from the percentage of produced water that is managed through reuse in other hydraulic fracturing operations. For example, in the Marcellus Shale region of the Susquehanna River Basin, ~14% of injected fluid was reused hydraulic fracturing wastewater, while ~90% of produced water was managed through reuse in other hydraulic fracturing operations.  186 Figure 6.3 Measured separation distance between drinking water resources and hydraulically fractured intervals in wells. Error bars in panel c display 95% confidence intervals (US EPA 2016a).  189 Figure 6.4 The location of public water system (PWS) sources having hydraulically fractured wells within 1 mi. Points indicate the location of PWS sources; point color indicates the number of hydraulically fractured wells within 1 mi of each PWS source. The estimates of wells hydraulically fractured from 2000 to 2013 are developed from the Drillinginfo data.  191 Figure 6.5 Typical class II underground injection well.  192 Figure 6.6 Schematic showing scenarios where aquifer exemptions might be requested (US EPA 2017).  194 Figure 6.7 Well plugging requirements by numbers of states (DOE/GWPC 2009).  195 Figure 6.8 Elements of state well plugging regulations (National Petroleum Council 2011).  196 Figure 6.9 Location of USEPA retrospective study areas.  197 Figure 7.1 USGS forecast for ground shaking intensity from natural and induced earthquakes in 2017.  206 Figure 7.2a Cross section of the Earth illustrating the maximum distance that shaking will occur for natural tectonic earthquakes originating at a depth of 10 km (6 mi), with M 3, M 4, and M 5.  206 Figure 7.2b Cross section of the Earth illustrating the maximum distance that shaking will occur for both natural and induced earthquakes originating at a depth of 2 km (1.5 mi), with M 3, M 4, and M 5.  207 Figure 7.3 Location of earthquakes in central and eastern United States showing an increase starting around 2009 and acceleration in 2013–2014.  208

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Figure 7.4 Distribution of oil and gas wells throughout Texas with historically significant petroleum fields labeled: Crs, Corsicana; ET, East Texas; F–I, Fashing–Imogene; GC, Goose Creek; KS, Kelly– Snyder; MW, Mexia–Wortham; Pnh, Panhandle; ST, Spindletop; Str, Stratton.  209 Figure 7.5 Graph showing earthquakes throughout Texas with M 3 or greater since 1975 and the associated regions of the state (Northeast, Gulf Coast, West Texas, and Panhandle) and where they occurred.  210 Figure 7.6 Diagram showing the mechanisms for inducing earthquakes (USGS 2017).  211 Figure 7.7 Two of the common stress regimes acting on the crust (a) and schematic failure envelopes illustration of the Mohr–Coulomb diagram (b) (IEAGHG 2013).  211 Figure 7.8 A USGS simulation of subsurface increase in fluid pressures related to horizontal and vertical distance from an injection well (USGS 2017).  212 Figure 8.1 Unsorted sample of St. Peter Sandstone, a major source for frac sand in the Midwest.  219 Figure 8.2 Silica dust clouds from delivery trucks loading into sand movers. The truck engines are on during this process, contributing to diesel particulate matter.  222 Figure 8.3 A conceptual example of a screw auger retrofit assembly to reduce silica dust during operations.  223 Figure 8.4 Volatile organic compounds from the flowback operations (left) were detected from the instrument (circle, right photo) (Esswein et al. 2011).  229 Figure 8.5 The geographic distribution where coccidioidomycosis (valley fever) is endemic overlies some areas in the southwest United States containing tight oil and shale gas deposits. Dust‐related disease can occur where surface disturbance occurs (CDC 2015).  230 Figure 8.6 La Brea tar pits in Los Angles, California, showing biogenic gas bubbles released by methane‐ producing microbial colonies that consume the natural asphalt.  231 Figure 8.7 Photograph of flooded well cellar at a conventional oil and gas field in California. The arrow is pointing to methane bubbles (arrow) released from the submerged wellhead (bolts). Crude oil sheens are also visible.  234 Figure 8.8 Generalized diagram of soil vapor intrusion through the sewer‐plumbing exposure pathway. The three houses to the right have vapor barriers with sub‐slab depressurization, which does not mitigate VOCs entering structures through the sewer‐plumbing exposure pathway (Jacobs et al. 2015).  236 Figure 8.9 Photoionization detector (PID), a commonly used vapor screening instrument at sites with petroleum hydrocarbons and chlorinated solvents (a). Schematic of photoionization detector (PID), a nondestructive vapor screening meter (b).  241 Figure 8.10 Flame ionization detector (FID) is a dual FID/PID analyzer with a dynamic range of 0.5–2000 ppm (PID) isobutylene and 0.50–50 000 ppm (FID) methane (a). Schematic of FID, a destructive vapor screening instrument that works well to detect methane (b).  241 Figure 8.11 Gas monitoring instruments and monitoring badges. (a) Multigas meter measures LEL, O2, H2S, and CO and VOC range of 0–2000 ppm, and sensors are available for CH4. (b) A single‐gas monitor with safety alarms for STEL and TWA is commonly used for worker exposure monitoring. Organic vapor passive air monitoring badges are used to measure worker exposure. (c) The badges contain charcoal sorbent. (d) Flexible inert charcoal wafer.  242 Figure 8.12 VOC screening using a hand pump (or bellows) and glass colorimetric gas and vapor detection tubes are useful for screening to identify possible gases.  242 Figure 8.13 Passive VOC analysis using passive synthetic sorber module (a). Axial samplers used for sampling VOCs in sewers and storm drains use TO‐17 method (b). Adsorbent cartridge samplers for air (c) and sub‐slab (d) are analyzed for VOCs using US EPA Method 8260 (GC/MS). Close‐up of adsorbent cartridge (e).   243 Figure 8.14 Passive sorber isoconcentration map showing benzene (μg). The underground storage tank (UST) containing gasoline was the source of the benzene.  244 Figure 8.15 Active air and soil vapor sampling containers for VOC analysis using (a) SUMMA canister and flow controller parts (HEER 2014). (b) One‐liter Tedlar bag with disposable sampling syringe and three‐way valve for filling (HEER 2014). SUMMA is a trademark of Molectrics, Inc.  245 Figure 8.16 (a) Schematic diagram for vapor flux chamber sampling of soil. (b) Photo of flux chamber (HEER 2014).  245 Figure 8.17 Schematic of a generic sub‐slab vapor sampling port to sample the crawl space or sub‐slab aggregate (gravels or drain rock) beneath a cement slab floor (NYSDOH 2006). Detailed photos above show vapor seals and sampling port variations (HEER 2014).  246 Figure 8.18 Permanent multiple soil vapor probes are installed in the same borehole allowing for VOC monitoring in different zones over time (US EPA 2015).  246

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Figure 8.19 Sub‐slab depressurization system (NYSDOH 2006). A vent pipe is routed up the side of the building to a location above the roof line (upper left), a fan can be used to draw vapors from beneath the slab (middle left), and a liquid gauge or manometer used to verify the systems is drawing vapors (lower left).  247 Figure 9.1 Active but temporary hydraulic fracturing process at a well in the Marcellus Formation, Pennsylvania, USGS (2017).  256 Figure 9.2 Producing gas well in Marcellus Formation, near Dimock, Pennsylvania. Photo taken from road.  256 Figure 9.3 Unconventional gas production in northeast Pennsylvania. No odors, dust, noise, or erosion were observed.  257 Figure 9.4 Flares of natural gas from the Bakken Formation in western North Dakota produce both noise and light pollution.  262 Figure 9.5 Flares of natural gas from the Bakken Formation in western North Dakota are visible from space.  262 Figure 9.6 Concept areas of compression, rarefaction and of a sound wave (OSHA 2013).  263 Figure 9.7 General concept of wavelength (OSHA 2013).  263 Figure 9.8 Sound pressure levels (dB) in a free field, distance in meters (OSHA 2013).  264 Figure 9.9 Sound reverberation showing the original and reflected sound waves (OSHA 2013).  265 Figure 9.10 Equal loudness contours for the human ear (OSHA 2013).  265 Figure 9.11 Portable sound level meter (OSHA 2013).  266 Figure 9.12 Generalized drawing of an industrial valve and flare showing a noise source radiating from the valve and the flare tip through the sound pathways to a receptor.   269 Figure 9.13 Conceptual diagram of the noise signature emitted from a natural gas flare operating under normal conditions.  270 Figure 9.14 Maximizing the number of wells (six wells) on each of nine well pads concentrates the impacts. The figure shows a Marcellus production pad design in map view draining a 2 square mile area.  278 Figure 10.1 Frac sand used as a proppant is mined in surface operations, which can impact ecological resources. Large deposits of the St. Peter Sandstone, a natural sand used in hydraulic fracturing operations as a proppant, are located in Wisconsin, Minnesota, and Iowa (Benson and Wilson 2014, 2015).  288 Figure 10.2 Silica sand mining, processing, and transportation operations in the upper reaches of the Mississippi River area in southeastern Minnesota can impact local air quality and affect wildlife habitat far from the unconventional oil and gas production areas.  289 Figure 10.3 Location of oil and natural gas wells near wetlands in a 36 square mile (93 km2) area of Burke County, North Dakota. This township contains some of the highest density of aquatic resources and extensive oil and gas development in the Williston Basin. Creator: Tara Chesley‐Preston/USGS http://www.usgs.gov/ blogs/features/usgs_top_story/understanding‐the‐relation‐between‐energy‐and‐the‐environment‐ using‐integrated‐science‐2/?from=image.  290 Figure 10.4 Aerial view of a drill rig on a well pad during installation of a well into the Bakken Formation in the Williston Basin in North Dakota.  291 Figure 10.5 Production pad over the Bakken Formation in the Williston Basin in North Dakota.  292 Figure 10.6 An example of Environmental Sensitivity Index (ESI) map shows a portion of New Jersey with biological resources notated (NOAA 2017).  294 Figure 12.1 Diagram of potential impact pathways (0–4) from unconventional oil and gas exploration and development.  316 Figure 12.2 Emergency response zones based on NIOSH, OSHA, USCG, and US EPA recommendations.  317 Figure 12.3 Concept of site conceptual model from the source zone to the human receptor.  318 Figure 12.4 Example of an exposure pathway assessment for an unconventional oil and gas well pad.  319 Figure 12.5 Example of a site conceptual model from source zone to receptor for an unconventional oil and gas well pad.  320 Figure 12.6 Generalized diagram of potential sample media collected during an investigation. The subsurface sediments, in this case, dry sand with some soil moisture in the unsaturated zone (A), the capillary fringe (B) that contains increasing water with depth as a film on the surface of sand grains, and the aquifer below the water table (C).  322 Figure 12.7 Example of a chart to evaluate possible media exposures to assist regulatory agencies to develope guidelines (concentrations) for decision‐making.  323 Figure 12.8 Direct push probe rig (top) uses an industrial jackhammer to drive the sampling tools. A continuous soil core collected using a probe rig is contained in an inert plastic liner (below). The sample tube containing stiff clay was cut open for lithologic characterization, not for laboratory analysis. A photoionization detector (PID) is shown on the cutting table in the photograph.  326

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Figure 12.9 Hollow stem auger drilling rig, left (USGS) and mud rotary direct circulation rig drilling in the Eagle Ford formation near Waco, Texas, right (Stan Paxton, USGS).  328 Figure 12.10 Gas chromatography equipment. Upper left: Agilent 5973 Network Mass Selective detector used to analyze semivolatile organic compounds (SVOCs) as well as diesel and heavier crude oils by US EPA Method 8015M. Lower left: Agilent 6890 Network GC System for volatile organic compounds such as BTEX compounds and other (VOCs) by US EPA 8260B. AS, autosampler; C, column in oven; G, carrier gases; GC, gas chromatograph; MS, mass spectrometer; PT, purge and trap.  333 Figure 12.11 GC‐MS process diagram. (1) Gas (He, N2, H2). (2) Sample injector. (3) Packed column GC in oven. (4) Mass spectrometer detector. (5) Recorder: chromatogram.  334 Figure 12.12 ICP mass spectrometer: Perkin Elmer SCIEX ELAN DRC Plus for metals. Detector (D), plasma (P), mass spectrometer (MS), and carrier gases (G).  335 Figure 12.13 ICP mass spectrometer process diagram. (1) Gas canister; (2) sample; (3) spray chamber; (4) carrier gas; (5) nebulizer; (6) auxiliary gas; (7) plasma gas; (8) ICP torch; (9) plasma; (10) interface; (11) ion lens; (12) quadrupole; (13) detector; (14) data recorder.  335 Figure 12.14 Differences in gas chromatographs in the C25–C30 range between crude oil (above) and weathered diesel oil (below) (US EPA 2007b).  338 Figure 13.1 Marcellus Shale gas production and decline curves.  353 Figure 13.2 Crude oil production from hydraulically fractured wells (US EIA 2016).  354 Figure 13.3 Natural gas production from hydraulically fractured wells (US EIA 2016).  354 Figure 13.4 General diagram showing properly destroyed wells.  363 Figure 13.5 A schematic showing the process from raw materials to product production to cleanup activities and the potential environmental impacts.  367 Figure 13.6 Diagram showing life cycle framework of resources including inputs (raw materials and resources), remedial technologies, and transportation of products and wastes, outputs, and large‐scale impacts (DTSC 2009).  367 Figure 13.7 Conceptual exposure scenarios in different media (HIDOH 2017: ITRC 2012).  370 Figure 13.8 Site‐specific assessment is based on regulatory approved media-specific chemical values. (SFRWQCB 2016).  370 Figure 13.9 Example of screening levels (SFRWQCB 2016).  371 Figure 13.10 Lynchburg, Virginia, railway spill in April 2014: (a) explosion, (b) tear in shell of the tank car, (c) smoldering tank cars in James River, and (d) derailment site (Photos: NTSB (2017)).  371 Figure 15.1 Example of common spill pathways (no scale implied).  390 Figure 15.2 On 8 Nov 2013, a train carrying Bakken crude oil derailed south of Aliceville, Alabama, into the adjacent wetlands. The derailment caused 23 tanker cars to be derailed; many were caught on fire and several of the cars were breached. (US EPAOSC 2013).  395 Figure 15.3 A massive fireball followed the derailment and explosion of two unit trains, one carrying 106 cars of Bakken crude oil in Casselton, North Dakota, on 30 December 2013 (US Pipeline and Hazardous Materials Safety Administration 2013).  395 Figure 15.4 After 1 October 2015, DOT‐117 (TC‐117 in Canada) is the new standard for all new unpressurized tank cars in use on North American railroads. Photo of DOT‐117 tank car (NTSB 2015) (above). DOT‐117 diagram with improvements listed (below).  399 Figure 15.5 Coproduced water has a variety of chemical characteristics that might be used to help identify the source of the water (Hayes and Severin 2012).  401 Figure 15.6 Tentatively identified compounds (TICs) from this volatile organic compound (VOC) analysis lists chemicals with low concentrations, which might otherwise be missed. Example VOCs in this printout include acetic acid and d‐limonene, which have component retention times of 6.1480 and 11.2388 minutes, respectively.  402 Figure 15.7 Typical piper diagram showing cations and anions present in water.  402 Figure 15.8 Biomarkers pristane and phytane are sourced from chlorophyll and are frequently preserved and present in crude oil and refined petroleum hydrocarbon products (Zafiriou et al. 1977).  403 Figure 15.9 GC‐IRMS is used for compound‐specific isotope analysis of carbon compounds (Hunkeler et al. 2008).  404 Figure 15.10 Transformations of contaminants, in this case, chlorinated aliphatic hydrocarbons (NJEHD 2005).  405

List of Figures

Figure 15.11 Dominant terminal electron‐accepting process, electron acceptors, and typical chemical species responses.  405 Figure 15.12 Carbon vs. hydrogen isotopes: biogenic and thermogenic methane.  408 Figure 15.13 Stable isotope ratios of water to differentiate water sources.  411 Figure 15.14 A Cl/Br vs. Cl cross‐plot with all data points and group averages, along with groundwater 2 Standard Deviation lines marked with the mean and a mark on the chloride axis indicating the secondary maximum contaminant level (250 mg l−1).  412 Figure 15.15 Conceptual model for prospective case study near an HVHF well pad (no scale implied).  413 Figure 15.16 Locations of US EPA retrospective case studies and associated hydrocarbon reservoirs (US EPA 2015a, b, c, d, e).  414 Figure 15.17 The case study sample location map for Bradford County, Pennsylvania, showing surface water, domestic well, and spring water sample locations (US EPA 2015a).  417 Figure 15.18 Generalized stratigraphic column (above) in northeast Pennsylvania. A generalized east–west cross section (below) for northeast Pennsylvania.  417 Figure 15.19 Diagram of drilled oil and gas wells in Bradford County since January 2000 showing totals starting in July 2008 extending to July 2013 (US EPA 2015a).  418 Figure 15.20 Map showing north–northwest and south–southeast orientation of gas well laterals in Towanda area of Bradford County as of February 2012 (US EPA 2015a).  419 Figure 15.21 Chloride/bromide weight ratio to chloride (mg l−1) provides differentiation of three groundwater samples with detectable concentrations from Salt Spring or the Marcellus Shale flowback fluids (US EPA 2015a).  420 Figure 15.22 The case study sample location map for Washington County, Pennsylvania, showing water sample locations (US EPA 2015b).  422 Figure 15.23 Generalized stratigraphic column in southwest Pennsylvania.  423 Figure 15.24 Sulfate/chloride weight ratio compared with bromide concentration (mg l−1) for surface water and groundwater, as well as Marcellus Shale flowback fluids, oil and gas brines, and other water types (US EPA 2015b). CFPP, coal‐fired power plant.  424 Figure 15.25 Detailed view of the Wise County sampling locations (US EPA 2015c).  425 Figure 15.26 A generalized stratigraphy column for the Fort Worth Basin. A, aquifer. B, Barnett Shale.  426 Figure 15.27 Killdeer retrospective case study locations. (a) Shows the 3‐mi radius and gives the locations of the non‐pad wells sampled as part of this study. (b) Shows a zoomed in view of the well pad and gives the locations of the pad wells sampled as part of this study (US EPA 2015d).  427 Figure 15.28 Stratigraphic column for Dunn County, North Dakota.  428 Figure 15.29 Generalized cross section of the shallow Killdeer aquifer that was deposited in an alluvial valley with a total area of about 74 mi2 in Dunn County.  429 Figure 15.30 Map showing the location of areas sampled during this case study. The Raton Basin retrospective case study was conducted in Huerfano and Las Animas counties, located within the Colorado portion of the Raton Basin (US EPA 2015e).  431 Figure 15.31 Generalized stratigraphic column for the Colorado portion of the Raton Basin.  432 Figure 15.32 The methane bubbles in the groundwater sample from a domestic well in the Little Creek Field in Huerfano County, Colorado. Headspace analysis was performed by US EPA (2015e).  436 Figure 15.33 The isotopic composition of dissolved methane in water samples collected by US EPA (2015e). RT, Raton Formation; RT–VJ, Raton–Vermejo Formations (comingled); VJ, Vermejo Formation. The zone boundaries (Jackson et al. 2013) reflect methane source.  437 Figure H.1 Soil textural triangle (USDA 2017).  495 Figure H.2 Soil type and particle diameter limits. 496

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­List of Tables Missing tables are found in Appendices F, G, H, I. Table 1.1 Summary of well stimulation techniques. 7 Table 2.1 Chronology of significant technological developments and events leading up to modern‐day well stimulation techniques. 27 Table 2.2 Modern‐day types of perforators. 35 Table 2.3 Plowshare Program experiments. 42 Table 2.4 USSR program experiments. 43 Table 3.1 General scheme of oil‐shale components. 54 Table 3.2 Classification of oil shale. 55 Table 3.3 Geologic provinces containing more than 5000 hydraulic fracturing treatment records associated with wells drilled from 2000 to 2010. 69 Table 3.4 Summary of subsurface information on major gas shales basins in the United States. 70 Table 4.1 General project phase and description of unconventional oil and gas production activities. 84 Table 4.2 Project phase and description of unconventional oil and gas production activities and approximate duration. 84 Table 4.3 Maturity indicators for the Ordovician Utica Formation, Ohio. 87 Table 4.4 Production recovery estimates for unconventional oil and gas fields. 91 Table 4.5 Summary of the classes of compounds commonly found at drilling and production sites. 96 Table 4.6 Summary of the types of drilling fluids and additives. 99 Table 4.7 Common geophysical logs used in drilling operations. 103 Table 4.8 General comparison of low‐volume and high‐volume hydraulic fracturing. 117 Table 4.9 Example of a single stage of a sequenced 15‐stage hydraulic fracture stimulation treatment. 119 Table 4.10 Example of chemical additives for fracturing, main compounds, and common uses (US DOE 2009). 120 Table 4.11 Estimated water needs for drilling and fracturing wells in selected shale gas provinces. 121 Table 4.12 Economic limit calculation. 128 Table 5.1 Summary of general concerns associated with tight oil and shale gas resource development. 138 Table 5.2 Project phase and description of unconventional oil and gas production activities and possible significant impacts based on resource category. 140 Table 5.3 Example of direct and indirect impacting factors for exploration–production life cycle. 142 Table 5.4 Scale of impacts for each resource. 144 Table 5.5 Summary of wastes produced during field operations. 147 Table 5.6 Gas composition of various US shale gas plays. 151 Table 5.7 Composition of natural gas at various stages of production and distribution. 152 Table 5.8 Common petroleum hydrocarbon products derived from the refining of crude oil. 153 Table 5.9 Summary of hydraulic fracturing fluid additives, main compounds, and common uses. 155 Table 5.12 Summary of pipeline distribution system. 162 Table 5.13 Examples and causes of pipeline failures. 163 Table 5.14 Urban areas in the United States situated over unconventional resources. 170 Table 5.15 Urban areas around the world situated over unconventional resources (non‐US). 171 Table 5.16 Potential hazards from exposure to selected hydraulic fracturing chemicals and selected chemicals associated with crude oil, combustion and fuels. 175

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Table 5.21 Summary of main challenges and opportunities of HVHF. 176 Table 6.1 Water use per hydraulically fractured well between January 2011 and February 2013. 185 Table 6.2 Summary of Studies Pertaining to Alleged Groundwater Impacts from Hydraulic Fracturing Operations. 197 Table 7.1 Summary of anthropogenic activity proposed to have induced earthquakes. 204 Table 7.2 Abbreviated modified Mercalli intensity scale. 205 Table 7.3 Earthquake magnitude classes. 207 Table 7.4 Summary of select reported cases of induced seismicity with ≥Mw 4.0. 210 Table 8.1 Description of possible air quality issues for each phase of exploration–production life cycle. 216 Table 8.2 Assumed Bakken gas composition. 217 Table 8.3 Gas flaring rate for Bakken wells, December 2011 Data. 217 Table 8.4 Summary of direct air measurements and mobile downwind sampling. 219 Table 8.5 Locations of selected frac sand sources in the United States. 220 Table 8.7 Mitigation measures for silica dust. 223 Table 8.8 Example PEL calculation for silica dust exposure. 225 Table 8.9 Examples of VOCs and methane emission sources. 228 Table 8.10 Exposure limits for selected petroleum hydrocarbons found at well sites. 229 Table 8.12 Selected laboratory analytical methods for soil vapor or indoor air contaminants and leak detection compounds. 238 Table 8.13 Summary of soil vapor and indoor air analytical methods. 239 Table 8.14 Common analytical conversion factors. 240 Table 8.16 Air and vapor sampling approaches and equipment. 240 Table 9.1 Example of setbacks. 259 Table 9.2 Common background noise levels. 264 Table 9.3 Description of primary noise sources, examples, and duration. 264 Table 9.4 Temporary noise associated with well site operations. 268 Table 9.5 Examples of some socioeconomic indicators, measurements, and specific analyses. 273 Table 9.6 Example of truck trips for drilling, hydraulic fracture stimulation, and flowback management. 277 Table 10.1 Example from Maryland of recommended Riparian Setbacks. 285 Table 10.2 Examples of mitigation measures for each of the seven phases of oil and gas exploration–production life cycle. 286 Table 10.3 Overview of potential impacts and mitigation measures for wildlife habitat issues. 289 Table 11.1 Federal exemptions relating to well stimulation. 301 Table 11.2 State legislation proposing HVHF disclosure requirements as of 31 May 2012. 305 Table 11.3 State legislation proposing or enacting moratoriums or impact studies. 312 Table 11.4 Legislation addressing authority to regulate as of 31 May 2012. 312 Table 12.1 Example observations of HVHF impacts at different locations with observations, impact timing and with response actions. 319 Table 12.2 Common chemicals found at oil and gas facilities based on industry segment. 321 Table 12.3 Example of hypothetical scenario sampling plan elements. 324 Table 12.4 Types of samples by media. 324 Table 12.5 Field screening methods for VOCs, including petroleum hydrocarbons. 330 Table 12.6 Summary of common analytical methods for VOCs, including petroleum hydrocarbons. 336 Table 12.7 Carbon range and occurrence. 337 Table 12.8 Selected compounds used in hydraulic fracturing products. 338 Table 12.9 Well conditions and confirmation laboratory analyses. 340 Table 12.10 Baseline groundwater monitoring analysis for unconventional oil and gas areas. 341 Table 13.1 Estimate of various unconventional oil and gas operations. 352 Table 13.2 Data for landowner royalty calculation. 353 Table 13.3 US crude oil and natural gas production (2000–2015). 355 Table 13.4 Pennsylvania real estate. 356 Table 13.5 Town of Flower Mound, Texas, and home prices near well sites. 356 Table 13.7 Estimate of the range of costs ($2017) for domestic well installation. 358 Table 13.8 Estimated costs (2017) for water supplies. 358

­List of Table

Table 13.9 Estimated costs for small domestic to large municipal water treatment systems. 359 Table 13.10 Estimated costs for soundproofing equipment sheds. 359 Table 13.11 Assumed heavy truck trips used for the construction and operations of a single unconventional gas well in Pennsylvania. 360 Table 13.12 Examined truck trips per HVHF well and multiple wells. 360 Table 13.13 Range in price for new road construction and repair per mile (1.6 km). 361 Table 13.14 Characteristics of roads assumed to be used for construction and operation of shale gas wells in Pennsylvania. 361 Table 13.15 Estimated consumptive road use and costs per lane mile driven by trucks used for the construction and operation of shale gas wells in Pennsylvania. 361 Table 13.16 Costs for road degradation based on a state or regional scale. For larger road degradation studies on a state scale, the costs are in hundreds of millions of dollars. 362 Table 13.17 Estimated costs for locating orphan wells. 362 Table 13.18 Cost for destroying orphan wells. 363 Table 13.19 Estimated costs for subsurface investigations and sampling. 363 Table 13.20 General costs for an environmental sampling project (10 samples). 364 Table 13.21 Costs of other services. 365 Table 13.22 Green Remediation Evaluation Matrix Checklist (GREM) (DTSC 2009). 368 Table 13.24 Environmental concerns related to chemical family. 370 Table 13.25 Description and costs for railway spills. 372 Table 14.1 Tort litigation involving hydraulic fracturing (and related cases). 378 Table 14.2 Types of plaintiffs. 386 Table 14.3 Type of oil and gas company plaintiff (N = 14 for each of small/large, public/private, local/ national). 386 Table 15.1 Common causes of spills and leaks. 391 Table 15.2 Spill studies using public data. 392 Table 15.3 Summary of incidents from State Data. 392 Table 15.4 Sources of spills (2005–2014) from State Data. 392 Table 15.5 Pathway of spills (2005–2014) from State Data. 392 Table 15.6 Spills 2005–2014 from well communication pathway from State Data. 393 Table 15.8 Physical and chemical characteristics of Bakken crude oil. 394 Table 15.9 Summary of rail accidents. 396 Table 15.10 Processes, media, and recommended sample type for oil spills. 397 Table 15.11 Combustion of Bakken crude oil and estimated emissions. 398 Table 15.12 Number and type of administrative, environmental, health, and safety violations. 400 Table 15.13 List of major ions, trace metals, nutrients, physical properties, selected analytical method, and detection limits. 403 Table 15.14 Chemical ratios to identify salt sources. 406 Table 15.15 Forensic methods to differentiate methane sources. 408 Table 15.16 Selected isotopes used in differentiating sources of water or methane related to unconventional oil and gas operations. 409 Table 15.17 General isotope ratios of boron and lithium illustrate the general concept of produced fluid differentiation. 410 Table 15.18 Summary of US EPA case study locations. 415 Table 15.19 Summary of US EPA field parameters used in retrospective case studies. 415 Table 15.20 Analyte groups and example constituents. 416 Table 15.21 Northeast Pennsylvania data source summary. 418 Table 15.22 Southwest Pennsylvania data source summary. 423 Table 15.23 Summary of water quality exceedances for Washington County, Pennsylvania. 423 Table 15.24 North Texas data source summary. 426 Table 15.25 West North Dakota data source summary. 429 Table 15.26  Tert‐butyl alcohol (TBA) concentrations in two groundwater monitoring wells. 430 Table 15.27 Southeast Colorado data source summary. 433 Table 15.28 Chemicals detected during October 2011 to April/May 2013 in US EPA study area. 433

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­List of Table

Table 15.29 Chemical additives for HVHF fluids used in the Raton Basin in Colorado. 434 Table 15.30 Various ways to produce tert‐butyl alcohol (TBA). 435 Table G.1 Checklist for emergency response. 486 Table G.2 Firefighting procedures. 486 Table G.3 Non‐fire spill responses. 486 Table G.4 Petroleum hydrocarbon characteristics. 487 Table G.5 Bakken crude oil characteristics. 487 Table G.6 Bakken crude oil characteristics. 487 Table G.7 Effective health and safety program. 488 Table G.8 Occupational limits in air (ppmv). 488 Table G.9 Worker training. 488 Table G.10 Human health effects of crude oil. 489 Table G.11 Human health effects of crude oil constituents. 489 Table G.12 Emissions of toxic chemicals released from burning 1 kg of crude oil. 490 Table G.13 Health protective concentrations within 3 media for six petroleum range compounds. 490 Table G.14 Health protective concentrations of constituents within crude oil. 490 Table H.1 Size of various sediments. 496 Tables in Appendix I Table 4.14 Checklist for general exploration–production life cycle inspections and documentation. 503 Table 4.15 Checklist for drilling plan and operation activities. 505 Table 4.16 Checklist for prospect evaluation, hazard assessment, special resource identification, and site‐specific considerations. 505 Table 5.10 Checklist of some exempt and nonexempt exploration and production waste streams. 506 Table 5.17 Checklist for worker safety standards. 506 Table 5.18 Checklist of mitigation plans and documentation of impacts. 509 Table 5.20 Checklist of sources of information. 510 Table 8.6 Safety checklist for reducing air quality impacts at oil and gas facilities and mine sites. 512 Table 8.11 Checklist for air sampling for possible chemical interference. 512 Table 8.15 Checklist for air and soil vapor field sampling. 513 Table 8.17 Checklist for air emissions related to hydraulic fracturing. 514 Table 9.7 Checklist of potential visual impacts of unconventional oil and gas operations. 515 Table 12.2 Checklist for site conceptual model, sampling plan, and investigation. 517 Table 12.10 Checklist for sampling groundwater and surface water related to drilling or hydraulic fracturing operations. 517 Table 13.6 Checklist for existing wells and new wells. 519 Table 13.23 Checklist for green remediation evaluation matrix (GREM). 520 Table 15.7 Train accident response checklist. 522

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Foreword Oil and gas literally fuels and lubricates the machines of  industrial society, and the shale revolution of the mid‐2000s has and will continue to transform the nation and global economy in significant ways for decades. Carbon‐based unconventional fossil fuels such as those liberated from tight oil sands or shale gas source rocks combine horizontal drilling with specialized production enhancement chemicals that are injected under high pressure using high‐volume hydraulic fracture (HVHF) stimulation techniques. Stimulation of oil and gas wells and reservoirs via fracturing to enhance production has a long history commencing in the early to mid‐1800s. With the first gas well in 1825 in the Marcellus Shale of Devonian age  in the village of Fredonia, Chautauqua County, New York, and the first successfully drilled oil well near Titusville, Pennsylvania, by Edwin Drake in 1859, those involved in the exploration and extraction of oil and gas have developed innovative and ingenious ways of enhancing production over the decades. Within a few years, artificial fracturing was used in Pennsylvania to coax waxier crude oil out of the tight reservoir rocks. By the late 1940s, what we recognize today as hydraulic fracturing was tested with promising results in a well a few miles east of Duncan, Oklahoma, in the giant Hugoton gas field in Kansas. According to some estimates, by 1988, prior to the modern shale gas boom, the hydraulic fracturing process had been used in oil and gas fields on nearly one million wells. If the technology has been around and used for decades, then why all the controversy and environmental concern? The answer is one of scale. Combined with the development of horizontal drilling techniques, injection strategies, and associated techniques and developments, well stimulation would accelerate as if on steroids to what we refer to today as high‐volume hydraulic fracturing (HVHF). Huge volumes of water would be needed for injection, ­ anner, and then the liquid recovered managed in some m commonly reinjected elsewhere. The end result is a number of environmental issues being raised and allegations of environmental harm, surface water and groundwater contamination, and other environmental

concerns. If that was not enough in an anti‐fossil fuel environment, rejection of associated fluids via reinjection was being alleged as the cause for earthquakes in certain parts of the country. The topic is controversial. The controversy regarding hydraulic fracture stimulation, commonly called “fracking,” reminds us that no series of advances in technologies are entirely positive or negative in their impacts. In the United States there is an historic split between surface rights owners of the real estate and the mineral rights owners of the subsurface resource. For every operator, landowner, and investor reaping the financial rewards of using the advanced technologies, there are countless neighbors inconvenienced by industrial processes taking place so close to their houses and concerned about possible health and environmental impacts. The information that has been published in a variety of sources and venues is voluminous. That there are many unanswered questions and uncertainties about this industrial process is the reason we evaluated thousands of pages of reports and hundreds of books and publications to develop a guide for those most affected  –  landowners, operators, neighbors, regulators, workers, and others interested in a better understanding of the processes and ways to protect the environment. Our intention was to review the data and literature and present our findings such that a county commissioner or supervisor could understand some of the technical tools used to investigate allegations of fugitive gas emissions or an attorney representing a landowner might better understand sub‐slab vapor sampling methods or air screening equipment. The book includes tables and check lists so that an environmental group can verify that all the appropriate documents have been submitted to the appropriate agencies or the worker or owner at a silica sand mine can read an overview of safety practices to minimize particulate dust exposure. The book was also designed so students, regulators, environmental or resource geologist, and engineers can find a summary of the topics. It was also written so that an insurance carrier providing coverage for the operators, infrastructure, facilities in the area of unconventional oil and gas drilling and production, pipelines or refining, and the residences

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Foreword

and communities nearby has an understanding of the HVHF processes, exposure risks, and environmental uncertainties. Mitigation measures are included for all of the impacted resources and issues, and a site‐specific impact analysis methodology is included in appendices to assist those interested in the nearby impacts that are occurring on‐site or a short distance from homes or businesses. What follows in this book is a rational discussion of the environmental issues and impacts associated with the exploration, extraction, and production of unconventional resources via HVHF technology. The chapters to follow also serves as a handbook for communicating, documenting, sampling, and investigating environmental concerns relating to HVHF. In this book, the benefits of HVHF and the importance of making the US energy independent by drilling domestic energy resources and providing a lower carbon footprint fuel are weighed against the potential environmental impacts to nearby residents and the ecosystem. In today’s world, it is easy to criticize the oil and gas industry despite all the benefits this industry has provided in many aspects of our

society. With a large investment in safety and environmental ­protection, the oil and gas industry provides increased economic development and employment while enriching their shareholders. With the access to domestic unconventional oil and natural gas resources, the industry has  the responsibility to protect human health and the environment per their operating permits and within all safety and environmental laws and regulations. This book was developed as a practical guide to help understand and mitigate adverse environmental impact by focusing on the side effects and unintended consequences of unconventional resource extraction and to facilitate the communication and education about the various processes, environmental aspects, safety issues, and risks involved with producing, transporting, storing, and refining unconventional hydrocarbon resources. James A. Jacobs Pt. Richmond, CA, USA Stephen M. Testa Mokelumne Hill, CA, USA

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­Acknowledgments We are indebted to all those colleagues who have answered our numerous questions and provided insight and guidance as we aimed to understand and present a comprehensive assessment of environmental impacts and risks associated with the process we referred to ­simply as fracking. We thank Don Clarke who provided certain images that were used in the preparation of this book. A  special acknowledgement to the Petroleum History Institute who provided permission to republish the majority of an article prepared for their journal Oil‐ Industry History pertaining to the historical ­development of well stimulation. Lydia Testa assisted in preparation of the Table of Contents and certain tables contained in the manuscript. James Jacobs – My interest in artificial fracturing goes back to my background as an oil geologist in the early 1980s. At that time, I met Thomas Chambers Roberts, who was not only a successful oil explorer in his own right in Oklahoma in the 1920s but also a grandson of Walter Brooke Roberts, who with his brother, Edward A.L. Roberts, developed the Roberts Torpedo, one of the first artificial fracturing techniques used in the oil and gas industry in Titusville, Pennsylvania. T.C. Roberts shared his love of the oil patch and showed me dozens of glass plates of early Titusville oil operations. I also thank him and his family, including Edward Thomas Roberts, great grandson of W. B. Roberts and Eric C.W. Dunn, great‐great grandson of W.B. Roberts for sharing stories and photos of the fracturing techniques and the early

days of the oil industry in Titusville. I also want to thank  Carl and Nancy Harvatine of Harvatine Farms (Thompson, Pennsylvania) located in the Marcellus Shale region. The Harvatines were generous to host me and my son Elliott for a few days in August 2015 at their farm. They arranged local tours around this scenic northeast Pennsylvania area, an area with some of the earliest Marcellus Shale gas production, to see the wells and other farms and operations associated with fracking. Their daughter, Laura Harvatine, arranged for the visit and her son, Justin, showed us around the area as well. A special thanks goes to Olivia Jacobs for final proof reading. Stephen Testa – My interest in this topic emerged as a historian in the development of oil and gas since its infancy and notably, in the development of oil and gas resources in California. My knowledge base expanded significantly when I served as president of the Energy Minerals Division of the American Association of Geologists in 2010–2011, and I cannot thank the various individuals enough for their patience and sharing of their knowledge in regard to unconventional and alternative resources. Lastly, our appreciation goes out to the individuals at  Wiley Publishers, notably Wiley Associate Editor Michael Leventhal, Project Editor Beryl Mesiadhas and Production Editor Gayathree Sekar who exhibited extraordinary patience and assistance in the preparation of this book. The authors are solely responsible for any shortcomings and errors.

1

1 Introduction 1.1 ­Energy and the Shale Revolution As a nation, and since the 1970s, energy independence has been more of a dream than a reality as we have ­witnessed the ups and downs of the oil and gas industry over the past several decades. The history of the oil and gas industry is that of ups and downs, but also one of technological innovation and ingenuity since the first well for gas was drilled in 1825 in the Marcellus Shale of Devonian age in the village of Fredonia, Chautauqua County, New York, and the first successfully drilled oil well near Titusville, Pennsylvania, by Edwin Drake in 1859. In the twenty‐first century, technological advances continue to drive the energy landscape and have signifi­ cant benefit beyond just energy policy. Our nation’s independence and reemergence as an energy leader largely reflects technological advances in the extraction of oil and ­natural gas from shale formations. Since the beginning of the twentieth century, the oil and gas industry has been vital to our energy needs. This industry and the infrastructure that supports it employ more people than any other industry. As of 2013, the entire natural gas and oil industry supported 9.2 million US jobs, accounted for 7.7% of the US economy, and deliv­ ered $86 million per day in revenue to the federal govern­ ment. Between 2007 and the end of 2012, the Energy Information Administration (EIA) in 2013 reported that total US private sector employment increased by more than one million jobs, or about a 1% increase, whereas employment within the oil and natural gas industry increased by more than 162 000 jobs, or about a 40% increase (Figure  1.1). However, employment in oil and natural gas extraction and support activities continued declining from levels reached in the fall of 2014–2011 lev­ els, just before the onset of falling oil prices (EIA 2016). Currently, there are 27 states that account for 99.9% of the oil and natural gas production in the United States, with about 33 states reporting oil or gas production. What is interesting about this however is that as of 2015 there were no 98%), with additional chemicals added to reduce friction, corrosion, bacterial‐growth, among other benefits during the stimulation process

Low viscosity slick‐water fluids generate fractures of lesser width and therefore greater fracture length. This tends to theoretically increasing the complexity of the created fracture network for better reservoir‐to‐wellbore connectivity

Slickwater fluid requires high pump rates to achieve flow velocities sufficient to overcome the tendency of the proppants to settle resulting in premature treatment termination and poor productivity. High viscosity that accomplishes this objective may significantly reduce the desired fracture complexity.

Slickwater fracturing is probably the most basic and most common form of well stimulation in unconventional gas. More than 30% of stimulation treatments in 2004 in North America have been slickwater fracturing

The long fracture closure times and the lack of efficient gel delayed breakers makes the proppant placement advantage of gel systems very limited as proppant settles while gel is breaking up and fracture has not yet closed.

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Zipper fracturing (ZF)

Zipper fracturing involves simultaneous stimulation of two parallel horizontal wells. Fractures are created in each cluster which is intended to propagate toward each other so that the induced stresses near the tips force fracture propagation to a direction perpendicular to the main fracture

Typically makes use of slick‐water as the fracturing fluid as applied to shale formations

Cavitation hydrovibration fracturing (CHF)

A proprietary technique developed at the Institute of Technical Mechanics in Dnipropetrovsk, Ukraine, and is designed to fracture rock using a pressurized water pulse action

The technology has not been tested yet to enhance gas recovery in conventional reservoirs, nor for shale gas production

Hydra‐jet fracturing (HJF)

Combines hydrajetting with hydraulic fracturing

Appears to offer improvements on how the fractures are initiated, but it does not offer substantial advantages regarding the usage of water and chemical additives in the fracturing fluid

Exothermic hydraulic fracturing (EHF)

The idea of injecting chemicals during the hydraulic fracturing treatment that – upon reaction – generate heat and gas. The temperature and gas increase then create localized pressure that results in thermal and mechanical fracturing

A likely shortcoming of this technique is the localized effect. Unconventional gas reservoirs, being so tight, require stimulation that reaches far into the reservoir. As shown in thermal heavy oil recovery projects, it takes substantial energy (or well count) to cover a large extension of the reservoir with relevant temperature changes

This idea was tested in laboratory specimen (cores) collected from tight reservoirs in Saudi Arabia. The permeability of tested cores showed significant increase after applying the new treatment technique

Dynamic loading (introduces a large amount of energy to a small volume of material which creates a large area of cracks. As the loading wave spreads inside the material, it will create fragmentations, thereby connecting the initial and newly created network of cracks) (Continued )

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Table 1.1  (Continued) Fracturing technique

Electric fracturing

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Fracturing technique variants

Pulsed arc electrohydraulic discharges (PAED)

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Description

Electricity is used to induce mechanical loads into the rock. If high enough, this loading will fracture the rock

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Potential advantages

Potential environmental advantages: (i) water usage much reduced or completely eliminated; (ii) few or no chemical additives are required

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Potential limitations

Limited capability of increase rock permeability away from the wellbore

Remarks

Both identified technologies are at the concept stage

Proppant not carried into the fracture Can only replace hydraulic fracturing only for small to medium treatments, i.e. the fracture penetration is somewhat limited

Plasma stimulation and fracturing technology (PSF) Explosive fracturing (solid propellents)

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Plasma stimulation is reported as ready for being tested in the field Explosives are used to fracture rock formations and hence stimulate production

Potential environmental advantages: (i) water usage completely eliminated; (ii) no chemical additives are required.

Can replace hydraulic fracturing only for small to medium treatments, i.e. the fracture penetration is somewhat limited.

Minimal vertical growth outside the producing formation.

Proppant is not carried into the fracture. Instead, propellant fracturing relies upon shear slippage to prevent the fracture from fully closing back on itself.

Multiple fractures. Selected zones stimulated without the need to activate packers. Minimal formation damage from incompatible fluids. Homogeneous permeability for injection wells. Minimal on‐site equipment needed. Lower cost when compared to hydraulic fracturing.

The energy released underground, albeit relatively low, could potentially induce seismic events. Problems of wellbore damage, safety hazards, and unpredictable results

In the late 1960s nuclear devices were tested as a mean to fracture rock formations in order to enhance the recovery of natural gas. Techniques based on explosive fracturing seem to have been largely superseded. On the other hand, techniques based on propellant fracturing are commercially available and have been used on shale formations, but very limited information on the scale is available. New techniques are currently being developed (for instance, Dry Fracturing EPS)

Can be used as a pre‐ fracturing treatment (to reduce pressure losses by friction in the near wellbore) Nuclear fracturing Pneumatic fracturing (introduces highly pressurized air or other gas to extend existing fractures and to create a secondary network of fissures and channels)

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Air N2

Air or any other gas is injected at a pressure that exceeds the natural strength as well as the in situ stresses present in the formation

Potential environmental advantages: (i) water usage completely eliminated; (ii) no chemical additives are required.

Limited possibility to operate at shallow depth  Limited capability to transport proppants

 Potential for higher permeabilities due to open, self‐propped fractures that are capable of transmitting significant amounts of fluid flow

Shallow shale formations have been fractured with pneumatic fracturing (EIA 1993) with the purpose of facilitating the removal of volatile organic contaminants. Pneumatic fracturing with gaseous nitrogen is applied to shale gas production, but limited information on the scale is available

Other methods Thermal (cryogenic) fracturing

Potential environmental advantages: (i) water usage much reduced or completely eliminated; (ii) no chemical additives are required.  Could be used in conjunction with CO2 sequestration schemes.

Large quantities of liquid CO2 would be needed.  Long times required: CO2 injection would need to occur for several years, and gas production would only start after two years from the beginning of the treatment

The concept idea has been proposed for tight formations

 Reduction of formation damage.  Enhance gas recovery by displacing the methane adsorbed in the shale formations Mechanical cutting of the shale formation

None identified Potential environmental advantages: (i) water usage much reduced or completely eliminated; (ii) no chemical additives are required

This is a technique specifically thought for shale formations. The technique is at the concept stage

 Possibly enhanced recovery of total gas in place, accelerated rates of production, and development of reserves in fields that would not otherwise be produced (Continued )

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Table 1.1  (Continued) Fracturing technique

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Fracturing technique variants

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Description

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Potential advantages

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Potential limitations

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Remarks

Enhanced bacterial methanogenesis

Potential to tap into vast hydrocarbon resources of immature source rock   Potential environmental advantages: no usage of water nor chemical additives, etc.

None identified

Enhanced bacterial methanogenesis appears to be at the concept stage. The technique has been successfully applied in laboratory specimen

Heating of rock mass

Water usage much reduced or completely eliminated   No chemical additives are required

None identified

The technique is applied for producing oil shale. No information on the extent of the use. It is at the concept stage concerning application for other unconventional hydrocarbons such as shale gas

Source: From Gandossi (2013).

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Introduction

The most commonly used fracture method in the oil and gas industry is hydraulic, since water is generally available, can be recycled or treated, and is an uncom­ pressible compound. Water can withstand pressures and temperatures found in the subsurface, and it can double as a carrier fluid for chemical additives and proppants. The term “hydraulic fracturing” is widely used to mean the process of fracturing rock formations with water‐based fluids, albeit hydraulic does not nec­ essarily applied to strictly water and includes all tech­ niques that make use of liquids (including foams and emulsions) as the fracturing agent. This is of environ­ mental interest since public pressure on operators to conserve water resources during the hydraulic fractur­ ing operations have been well documented will con­ tinue, and improvements in the efficiency of the process are likely with the addition of green chemicals, gases, foams, and gels to lower the overall water use during the fracturing operations. There are several hydraulic fracturing techniques afforded to the opera­ tor based on site‐specific ­conditions. These techniques include the use of ­water‐based, foam‐based, oil‐based, acid‐based, alcohol‐based, emulsion‐based, and cryo­ genic‐based fluids. Cryogenic‐based fluids include such gases as carbon dioxide gas, nitrogen gas, and other compounds. Slickwater fracturing is probably the most basic and most common form of well stimulation in unconven­ tional gas, being used for more than 30% of stimula­ tion treatments in 2004 in North America. The fracturing fluid is composed primarily of water and sand (>98%), with additional chemicals added (namely, friction reducers, surfactants, and possibly other con­ tents such as ­p olyacrylamide, biocides, electrolytes, and scale ­inhibitor in variable quantities) to increase fluid flow velocity and sand transport and to reduce friction, corrosion, and bacterial growth, among other benefits during the stimulation process. Conventional fracturing is typically used in both vertical and hori­ zontal wells and in low‐permeability or “tight” reser­ voirs (i.e. sandstone), generally below a depth of 3000 m. A water‐based gel fluid is used with a medium proppant loading and 4–5 pumps operating at a com­ bined rate of up to 5 m3 of water per minute. This technique creates long, very fine fractures. The vol­ ume of fluid is usually